60 kV to 500 kV

Technical Interconnection Requirements

For

Power Generators

Revision: 0

October 2008

COPYRIGHT, BC TRANSMISSION CORPORATION, OCTOBER 2008

Disclaimer

This document is not intended as a design specification or as an instruction manual for the Power Generating Facility (PGF) connecting to the BCTC System and shall not be used by the Power Generating Facility proponent for those purposes. Persons using the information included in this document shall do so at no risk to BCTC, and they rely solely upon themselves to ensure that their use of all or any part of this document is appropriate in the particular circumstances.

The proponent, its employees or agents must recognize that they are, at all times, solely responsible for their PGF design, construction and operation. Neither BCTC nor any of its employees or agents shall be, nor become, the agents of the proponent in any manner whatsoever arising.

BCTC’s review of the specifications and detailed plans shall not be construed as confirming or endorsing the design or as warranting the safety, durability or reliability of the PGF. BCTC, by reason of such review or lack of review, shall be responsible for neither the strength, adequacy of design or capacity of equipment built pursuant to such specifications, nor shall BCTC, or any of its employees or agents, be responsible for any injury to the public or workers resulting from the failure of the PGF.

In general, the advice by BCTC, any of its employees or agents, that the PGF design or equipment meet certain limited requirements of BCTC does not mean, expressly or by implication, that all or any of the requirements of the law or other good engineering practices have been met by the proponent in its PGF, and such judgement shall not be construed by the proponent and others as an endorsement of the design or as a warranty, by BCTC, or any of its employees.

The information contained in this document is subject to change and may be revised at any time. BCTC should be consulted in case of doubt on the current applicability of any item.

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Acknowledgement

BCTC wishes to acknowledge the Alberta Electric System Operator, BC Hydro and Power Authority, Bonneville Power Administration, Hydro Quebec and Manitoba Hydro for certain selected material used in this document.

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Table of Contents

1. Introduction ........................................................................................................................ 1

2. Definitions........................................................................................................................... 2

3. Scope.................................................................................................................................... 5

4. General Requirements ....................................................................................................... 5 4.1 Generator Minimum Size .............................................................................................................. 6 4.2 Safety and Isolating Devices .......................................................................................................... 6 4.3 Point of Interconnection Requirements....................................................................................... 7 4.3.1 General Constraints........................................................................................................................................ 7 4.3.2 General Configurations.................................................................................................................................. 7 4.3.3 Special Configurations.................................................................................................................................11 4.4 Transformer Considerations....................................................................................................... 11 4.4.1 New Installations..........................................................................................................................................11 4.4.2 Existing Installations....................................................................................................................................12 4.5 Other Interconnection Considerations ...................................................................................... 12 4.5.1 Existing Equipment .....................................................................................................................................12 4.5.2 System Stability and Reliability ..................................................................................................................12 4.5.3 Protection and Control.................................................................................................................................12 4.5.4 Revenue Metering........................................................................................................................................13 4.5.5 Dispatching for System Operations and Maintenance...............................................................................13 4.5.6 Atmospheric and Seismic............................................................................................................................13 4.5.7 Physical Security..........................................................................................................................................13 4.6 Transmission and Substation Facilities...................................................................................... 13 4.7 Insulation Coordination ............................................................................................................... 13 4.7.1 Lightning Surges..........................................................................................................................................14 4.7.2 Switching Surges .........................................................................................................................................15 4.7.3 Temporary Over-voltages............................................................................................................................15 4.7.4 Neutral Shifts................................................................................................................................................15 4.8 Substation Grounding .................................................................................................................. 16 4.9 Inspection, Test, Calibration and Maintenance........................................................................ 17 4.9.1 Pre-energization Inspection and Testing.....................................................................................................17 4.10 Station Service ........................................................................................................................... 17 4.11 Black Start Capability .............................................................................................................. 17 4.12 Synchronizing Facilities............................................................................................................ 18 4.13 Certification of the Power Generating Facility..................................................................... 18 4.14 PGF Modelling and Data Requirements ............................................................................... 18 5. Performance Requirements............................................................................................. 18 5.1 Electrical Disturbances Requirement ........................................................................................ 18 5.2 Power Quality ................................................................................................................................ 19 5.2.1 Self Excitation and Resonance Phenomena ...............................................................................................19

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5.2.2 Power Parameter Information System........................................................................................................19 5.2.3 Voltage Fluctuations and Flicker ................................................................................................................19 5.2.4 Voltage and Current Harmonics..................................................................................................................20 5.2.5 Phase Unbalance..........................................................................................................................................20 5.3 Station and Switchgear................................................................................................................. 21 5.3.1 General .........................................................................................................................................................21 5.3.2 Station Insulation Requirements .................................................................................................................21 5.3.3 Clearances ....................................................................................................................................................23 5.3.4 Circuit Breaker Requirements:....................................................................................................................23 5.3.5 Circuit Breaker Rated Interrupting Times and Fault Clearing Times .......................................................23 5.4 Generators...................................................................................................................................... 24 5.4.1 Generator Active Power ..............................................................................................................................24 5.4.2 Generator Reactive Power Requirements...................................................................................................24 5.4.3 Generation Excitation Equipment Requirements.......................................................................................24 5.4.4 Governor Requirements...............................................................................................................................26 5.4.5 Voltage and Frequency Operation during Disturbances............................................................................26 5.4.6 Contingency and RAS Requirements .........................................................................................................28 5.5 Transformer Requirements......................................................................................................... 28 5.6 Transmission Line Design Requirements.................................................................................. 29 5.6.1 Environmental Considerations....................................................................................................................29 5.6.2 Connection to the BCTC System................................................................................................................30 5.6.3 Line Performance.........................................................................................................................................30 6. Protection Requirements.................................................................................................. 30 6.1 General Requirements.................................................................................................................. 30 6.1.1 Internal Fault Protection ..............................................................................................................................30 6.1.2 Equipment Rating ........................................................................................................................................31 6.1.3 Unbalance, Under-frequency and Under-voltage.......................................................................................31 6.2 Entrance Protection...................................................................................................................... 31 6.3 Transmission Line Protection Requirements ........................................................................... 32 6.3.1 Detection of Ground Faults .........................................................................................................................33 6.3.2 Detection of Phase Faults ............................................................................................................................33 6.3.3 Breaker Failure Protection of the PGF HV Circuit Breaker ......................................................................33 6.3.4 Prevention of Energization of Ungrounded Transmission Line by PGF..................................................33 6.4 Power Quality Protection............................................................................................................. 35 6.5 Under-frequency Load Shedding Protection............................................................................ 36 6.5.1 Frequency Relay Requirements ..................................................................................................................36 6.6 Batteries / Chargers / DC Supplies ............................................................................................. 36 7. Control and Telecommunications Requirements.......................................................... 37 7.1 Telecommunications ..................................................................................................................... 37 7.1.1 General .........................................................................................................................................................37 7.1.2 Telecommunications Media........................................................................................................................37 7.1.3 Telecommunications System for Operating Functions..............................................................................38 7.1.4 Telecommunications System for Teleprotection Functions ......................................................................38 8. System Operating Requirements..................................................................................... 39 8.1 Generation Scheduling and Control........................................................................................... 39 8.2 Remote Operations ....................................................................................................................... 40

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8.3 Generation Islanding .................................................................................................................... 40 8.4 Normal and Emergency Operations .......................................................................................... 41 8.5 SCADA, Telecommunications and Control .............................................................................. 41 8.6 Other Requirements ..................................................................................................................... 43 9. Commissioning Requirements ........................................................................................ 43 9.1 General............................................................................................................................................ 43 9.1.1 General Commissioning Requirements:.....................................................................................................43 9.2 Generator Commissioning Requirements................................................................................. 44 9.3 Protection Equipment................................................................................................................... 44 9.4 Telecommunications Equipment ................................................................................................ 45 9.5 Operating, Measurement and Control Systems Commissioning Requirements................. 45 9.6 Apparatus Commissioning Requirements ................................................................................ 45 10. Maintenance Requirements............................................................................................. 46 10.1 General........................................................................................................................................ 46 10.2 Scheduled Outages Requirements .......................................................................................... 46 10.3 Preventive Maintenance Requirements................................................................................. 46 10.4 Protection and Telecommunications Equipment ................................................................. 46 11. Regulatory and Reliability Requirements ...................................................................... 46

12. References ......................................................................................................................... 47 12.1 BCTC .......................................................................................................................................... 47 12.2 CSA ............................................................................................................................................. 47 12.3 IEEE Standards (www.ieee.org) ............................................................................................. 47 12.4 WECC Guidelines (WECC website)...................................................................................... 48 12.5 Others.......................................................................................................................................... 48 Appendix A – Wind Generation Interconnection Requirements............................................ 49

Appendix B – Protection Example Installations ...................................................................... 65

Appendix C – Power Parameter Information System.............................................................. 66

Appendix D – Data Requirements ............................................................................................. 69

Appendix E – Declaration of Compatibility.............................................................................. 77

Appendix F – Permissible Voltage Dips – Borderline of Visibility Curve ............................. 78

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1. Introduction

BC Transmission Corporation (BCTC) has prepared this 60 kV to 500 kV Technical Interconnection Requirements for Power Generators (the “TIR”) to identify technical requirements for connecting Power Generating Facilities (PGFs) to the BCTC System. The purpose of these requirements is to assure the safe operation, integrity and reliability of the BCTC System. Contractual matters, such as costs, ownership, scheduling, and billing are not the focus of this document. Transmission Services are not addressed by this document either. All requests for transmission services shall be made independent of the interconnection requests pursuant to the terms of BCTC’s Open Access Transmission Tariff (OATT). Please refer to the BCTC web site, www.bctc.com, for more information on the interconnection process, business practices, contractual matters and transmission services.

This document is not a design specification or an instruction manual and the information presented is expected to change periodically based on industry events and evolving standards. Technical requirements stated herein are consistent with BCTC’s current practices for system additions and modifications. These requirements are generally consistent with principles and practices of the North American Electric Reliability Corporation (NERC), Western Electric Coordinating Council (WECC), Northwest Power Pool (NWPP), Canadian Standards Association (CSA), Institute of Electrical and Electronics Engineers (IEEE), American National Standards Institute (ANSI), International Electrotechnical Commission (IEC), and Good Utility Practice. Standards of the above listed organizations and practices are also subject to change.

The Power Generator proponent (PG) shall submit all specifications of its facilities and detailed plans to BCTC to enable BCTC to conduct the technical review required to grant permission to interconnect the proposed project. The PG shall notify BCTC immediately in the event of any modifications to the detailed plans that could impact the performance of the interconnection.

The PG shall communicate any issues with BCTC’s Interconnections Office. Contact details for the Interconnections Office are:

BC Transmission Corporation Suite 1100, Four Bentall Centre 1055 Dunsmuir Street PO Box 49260 Vancouver, BC V7X 1V5

Phone: 604-699-7381 FAX: 604-699-7539 Toll Free: 866-647-3334 Email: bctc.interconnections@bctc.com

The PG will communicate directly with all regulatory and governmental authorities in order to ensure that the Power Generating Facility (PGF) is designed, constructed, operated and maintained in compliance with all applicable standards, statutes, regulations, by-laws and codes.

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2. Definitions

Balancing Authority (BA) – the responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance within its balancing authority area, and supports interconnection frequency in real time.

British Columbia Transmission Corporation (BCTC) – a corporation incorporated under the laws of the Province of British Columbia having its head office at Suite 1100, 1055 Dunsmuir Street, Vancouver, British Columbia V7X 1V5. BCTC is responsible for operating, maintaining, managing and planning the Transmission System.

BCTC System or Transmission System – the transmission system, protection, control and telecommunications facilities:

• Owned by BCTC or by BC Hydro and

• Operated by BCTC in British Columbia, including all additions and modifications thereto and repairs or replacements thereof.

British Columbia Utilities Commission (BCUC) – the British Columbia Utilities Commission is an independent regulatory agency of the Provincial Government that operates under and administers the Utilities Commission Act. The Commission's primary responsibility is the regulation of British Columbia's natural gas and electricity utilities. BCUC also regulates intra-provincial pipelines and universal compulsory automobile insurance.

Control Centres (Fraser Valley Office [FVO] and South Interior Office [SIO]) – BCTC operates a Primary (FVO) and a Backup (SIO) control centre that are functionally identical and are locations from which BCTC operates the Transmission System. By contract, BCTC also operates the BC Hydro distribution system and generation system. BCTC is responsible for meeting all Balancing Authority (BA) responsibilities as defined in NERC and WECC Standards for British Columbia.

Extra High Voltage (EHV) – voltage level between 300 kV and 800 kV.

Emergency – any condition where, whether by reason of a forced outage or concern for a forced outage, or otherwise, there is an imminent risk of equipment failure, or of danger to BCTC or PG personnel, the public or others, or a risk to the security or reliability of the PGF, the BCTC System or any other generation, transmission, distribution or other electric system interconnected with the BCTC System or the PGF.

Good Utility Practice – any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to be acceptable practices, methods or acts generally accepted in the WECC region.

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Island – a portion of the Transmission System consisting of load and generation, which has become isolated due to the tripping of transmission system elements.

Main Transmission System – the Transmission System facilities operated at 500, 360, 287 and 230 kV and some designated lower voltage transmission lines.

Maximum Power Injection (MPI) – this is the power in MW that can be injected into the transmission system at the Point of Interconnection.

North American Electric Reliability Corporation (NERC) – the North American Electric Reliability Corporation’s mission is to ensure the reliability of the bulk power system in North America. To achieve that, NERC develops and enforces reliability standards; assesses adequacy annually via 10-year and seasonal forecasts; monitors the bulk power system; evaluates users, owners, and operators for preparedness; and educates, trains, and certifies industry personnel. NERC is a self-regulatory organization, subject to oversight by the U.S. Federal Energy Regulatory Commission and governmental authorities in Canada.

Maximum Power Output (MPO) – this is the maximum possible output from the generator under ideal conditions. For hydro units this is usually at maximum head with the wicket gates fully open.

Point of Interconnection (POI) – as defined in the OATT.

Power Generating Facility (PGF) – a plant/site where generating and related transmission system, protection, control and telecommunications facilities are installed, which is connected to, and in synchronism with other generators connected to the Transmission System for the purpose of producing electricity.

Power Generator (PG) – an entity who is a proponent of or an owner of a Power Generating Facility. The PG may consume all or some of the electric energy produced at the Power Generating Facility.

Rated Power – the generator MVA multiplied by the rated over-excited power factor.

Remedial Action Scheme (RAS) – is designed to detect abnormal system conditions and take pre-planned, corrective action (other than the isolation of faulted elements) to provide acceptable system performance.

Standard Generator Interconnection Agreement (SGIA) – a legal document stating the contractual obligations of the PG and BCTC. The document covers, but is not limited to, issues relating to facility ownership, operation, dispute mechanisms, and technical requirements. The Interconnection Requirements are incorporated in the SGIA.

Transmission – lines operate at voltages 60 kV and above.

Western Electricity Coordinating Council (WECC) – WECC is the organization responsible for coordinating and promoting electric system reliability. In addition to promoting a reliable electric power system in the Western Interconnection, WECC will support efficient competitive power markets, assure open and non-discriminatory transmission access among members, provide a forum for resolving transmission access disputes, and provide an

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environment for coordinating the operating and planning activities of its members as set forth in the WECC Bylaws.

Wind Generating Facility (WGF) – a WGF is defined as any group of one or more Wind Turbine Generators (WTG) used for converting wind energy to electricity, and injecting the electric energy into the BCTC System.

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3. Scope

These technical requirements apply to all new or modified interconnections to the BCTC System, which is an AC system. Where a PG uses HVDC technology to transfer the PG’s power to the POI, it is the PG’s responsibility to install adequate equipment compatible with the BCTC System for interconnection. As each HVDC has its unique design, additional technical requirements will be determined on a case by case basis at the interconnection study stage. Specific requirements for Wind Generating Facilities (WGF) interconnection are included in the Appendix A – Wind Generation Interconnection Requirements.

The interconnection shall not degrade the safe operation, integrity and reliability of the BCTC System. These interconnection requirements are intended to protect the Transmission System but cannot be relied upon to protect the Power Generating Facilities (PGF). This document provides information on the interconnection requirements for use by Power Generator proponents (PGs) that have an interest in interconnecting to the Transmission System and identifies:

The minimum technical requirements the PG’s equipment shall meet if connecting to the Transmission System at or above 60kV, and

The expected system conditions their facilities will encounter when connected to the Transmission System.

These requirements ensure that the PG’s equipment shall:

At all times be compatible with the safe operation of the Transmission System;

Maintain a high standard of quality and reliability of electricity supply;

Meet BCTC’s applicable operating, dispatching, metering and protection requirements; and

Meet the requirements of regulatory agencies and authorities such as the British Columbia Utilities Commission (BCUC), the North America Reliability Corporation (NERC), and the Western Electricity Coordinating Council (WECC).

BCTC reserves the right to take whatever measures are necessary in its sole discretion to ensure the safe, reliable operation of the Transmission System.

The PG owns and is responsible for the design, installation, operation, and maintenance of all necessary equipment, station and transmission line facilities that are required to connect its facilities to the Transmission System, unless otherwise agreed to in writing. The PG is responsible for obtaining all regulatory approvals, including environmental assessment approvals, if necessary, for the construction and operation of its facilities.

4. General Requirements

The interconnection of PG’s equipment shall comply with codes, standards, and criteria applicable in BC, and with Good Utility Practice.

Construction of the PGF shall be performed in an environmentally responsible and safe manner in accordance with applicable Federal and Provincial regulations and standards.

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The PG shall notify BCTC prior to any alterations to its connected facilities, both during the design stage and after the PGF commences commercial operation. Changes that affect the PGF’s performance including station configuration, equipment rating, fault contribution, generator performance, control, protection schemes and protection settings require BCTC’s prior approval.

Extra High Voltage (EHV) requirements will be determined on a case by case basis; the additional requirements for the PGF could include but not limited to the following aspects, high speed clearing and reclosing, class 11 communications system, and insulation coordination to ensure comparable performance to the existing major transmission system.

4.1 Generator Minimum Size

Conventional synchronous generators are subject to generator self excitation if loaded with a capacitive load greater than 80% of the MVA rating of the machine, assuming a typical synchronous reactance of 125%. As unloaded transmission lines, in an islanding condition, are a capacitive load, generator self excitation could occur if the connected generator is too small to absorb the VARs from the transmission lines. PGF when connected to the Transmission System should meet the criterion that:

0.7 times 0n-Line Generation MVA > Open-ended Line Charging MVA

(Units with higher synchronous reactance will have to be proportionately larger.)

If this principle is not met, costly mitigations will be required.

4.2 Safety and Isolating Devices

At the Point of Interconnection, an isolating disconnect device shall be installed and shall meet the following requirements:

It physically and visibly isolates the Transmission System from the PGF.

It complies with safety and operating procedures of WorkSafeBC.

It is rated for the voltage and current requirements of the particular application.

It is gang operated.

It is operable under all weather conditions in the area.

It is lockable in both the open and closed positions.

It is accessible to BCTC at all times.

Its control and operation are governed by the operating agreements between the PG and BCTC (normally in the form of “Local Operating Orders” (LOOs)).

The disconnect device is provided for isolation and cannot normally be used to interrupt load current or significant line charging current. Its location, capacity and operating rules must be carefully established and documented.

The isolation device may be placed in a location other than the Point of Interconnection (POI) by agreement of BCTC and affected parties.

1 Class of communication system is referring to percentage of availability and is defined in WECC ”Communications Systems Performance Guide for Protective Relaying Applications”.

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BCTC personnel may lock the isolating device in the open position and install safety grounds:

For the protection of maintenance personnel when working on de-energized circuits;

If the connected facilities or BCTC equipment presents a hazardous condition; or

If the connected facilities jeopardize the operation of the BCTC System.

4.3 Point of Interconnection Requirements

4.3.1 General Constraints

The connection methods described below are examples of possible connection methods only and are not intended to be a guide to the PG as to which connection method is appropriate to the installation. The connection method is site and system dependent. As well, the telecommunication structure available (or lack thereof) is a key factor. Thus, BCTC will make the determination of connection method for each application at the time of interconnection studies.

Connected facilities shall not restrain BCTC from taking a transmission line, line section or other equipment out of service for operation and maintenance purposes. The interconnection line and all its components shall be designed and installed to be maintainable within BCTC’s need to maintain.

The PGF shall be designed for operation at short circuit (fault) levels that take into account future development of the BCTC System. The short circuit levels to be used in the design depend on the POI and future planned development, and are available on request.

4.3.2 General Configurations

Connection of new facilities into the transmission system generally falls into one of three categories:

a) Connection into an existing 60 kV to 500 kV bulk power substation with (depending on the bus configuration) the existing transmission and new connecting lines each terminated into bays containing one or more breakers;

b) Connection by looping an existing 60 kV to 500 kV transmission line into a new BCTC substation provided to terminate a new line from the PG; or

c) Connection into an existing 60 kV to 230 kV transmission line via a tap.

BCTC must maintain full operational control of the transmission path. This includes, but not limited to, SCADA control and monitoring of circuit breakers, disconnects and other equipment in the new substation. Any new equipment shall not degrade the operational capability of the line.

Safety and security rules are in place to prevent un-authorized personnel from having physical access to BCTC stations. Design consideration, particularly for protection and control, must include these rules.

The following Figure 1 illustrates Case (a). The pertinent points to this form of interconnection are:

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A dedicated line built, owned and operated by the PG is brought into an existing BCTC facility; and

The BCTC facility has been modified to accommodate a new line position. For example, if the existing BCTC bus arrangement is a ring bus, a new breaker is required to be installed in the ring to establish a new line position for the new radial line.

Note: In addition to the Motor Operated Disconnect Switch (MODS) at the BCTC station, a ganged disconnect is provided immediately on the PG side of the POI. This allows either party (BCTC or PG) to isolate the line without physical access to the other party’s facility.

Figure 1: Case (a) – Connecting into existing 60 kV to 500 kV BCTC Bulk Station

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The starting point for the evaluation of connection is a new radial line to existing or new BCTC facilities as shown in Figure 2. Modifications from this approach (such as the other examples that follow) will be determined on a case by case basis. Figure 2 Case (b1) illustrates a safe, reliable and flexible configuration where BCTC provides a switching station at the transmission right-of-way (ROW), adjacent to the line.

Figure 2: Case (b1) - New BCTC Station Connecting Into Existing Transmission Line at

ROW

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Case (b2), Figure 3 below, is a variant of Case (b1) where it is not practical to build a new station immediately adjacent to the existing transmission line right-of-way. As shown, BCTC transmission line extensions are brought to a new three breaker ring station near the PGF. The pertinent points to this form of interconnection are:

A short section of dedicated line or bus work built and owned by the PG is brought into a new BCTC three breaker ring facility; and

The BCTC facility is located physically adjacent to the PGF.

Figure 3: Case (b2) - New BCTC Station Connecting near PGF

BCTC Facility

POI

New PG Facility

BCTC Facility

New BCTC 3 CB Ring Facility

BCTC Transmission

Line Extensions

Facilities at one common site

future

Future station service supply

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Case (c) is shown in Figure 4 below. Generally, this installation is not desirable because of its negative impact on transmission protection and security.

If it is to be considered, three-terminal line current differential protection may resolve the protection issues. However, it will require a substantive (broadband) telecommunications infrastructure. Furthermore, such an installation may not be possible if there are existing taps or taps planned for the transmission line.

Note that a line with three terminals affects BCTC’s ability to protect, operate, dispatch and maintain the transmission line. BCTC determines the permissibility of multi-terminal line connections on a case-by-case basis. BCTC will define specific protection requirements for the PGF terminal of a multi-terminal line in those few cases where they can be permitted.

Figure 4: Case (c) - PG Tapped To BCTC Transmission Line

4.3.3 Special Configurations

Main Transmission System is the backbone of the British Columbia transmission system and provides the primary means of serving large geographical areas. Line taps will not be considered. If connections are permitted, BCTC will construct a substation at the POI with sufficient redundancy in accordance with Good Utility Practice to maintain reliability and security of the main grid system. Selection of an alternative POI encouraged.

4.4 Transformer Considerations

4.4.1 New Installations

Transformers connecting to the Transmission System where a source of real power flows through the transformer to the BCTC high voltage transmission system shall provide a source of ground current on the high voltage side. A YG-Δ or a YG- Δ-YG transformer with the Y-ground connection on the high voltage side can accomplish this. A YG-YG connection is only appropriate if there is a sufficient ground source on the low voltage side and will need to

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be evaluated by BCTC before it can be permitted. Auto-transformers with tertiary windings are acceptable for connecting lower voltage collector networks.

4.4.2 Existing Installations

Co-generation added to existing load sites served by Δ-YG transformers may require transformer replacement or additional equipment, such as a grounding bank, to avoid ungrounded system operation. If the Δ-YG is permitted to be retained, relay protection schemes may also be required to ensure immediate disconnection of the power source following a disconnection of the transmission system. BCTC will consider these on a case by case basis.

4.5 Other Interconnection Considerations

4.5.1 Existing Equipment

The proposed new connection may cause existing system equipment such as transformers, power circuit breakers, disconnect switches, arresters, and transmission lines to exceed their ratings. Replacement of the impacted equipment or development of alternate plans of service will be part of the interconnections studies.

4.5.2 System Stability and Reliability

The BCTC System has been developed with careful consideration for system stability and reliability during disturbances. The type of connection, size of the source or load, breaker configurations, source or load characteristics, and the ability to set protective relays will affect where and how the connection is made. The PG should expect to be required to participate in special protection or Remedial Action Schemes (RAS) including automatic generation tripping and load shedding.

4.5.3 Protection and Control

BCTC coordinates its protective relays and control schemes to provide for equipment protection and to minimize disruption of services during disturbances. New connections usually require addition or modification of protective relays and/or control schemes, including replacement or modification of equipment at the remote terminal(s). The new protection shall be compatible with existing protective relay schemes and present standards. The addition of voltage transformers, current transformers, or pilot scheme (transfer trip) may also be necessary. BCTC will recommend or specify, as appropriate, protective relay systems to protect BCTC System.

Should the PG select a relay system different from BCTC applications for other parts of the PGF, BCTC reserves the right to perform a full set of acceptance tests prior to granting permission to use the selected protection scheme. PG selected equipment shall have interfaces compatible with BCTC equipment.

BCTC will assess whether piloted or non-piloted line protection is required on a case by case basis

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4.5.4 Revenue Metering

It is important to incorporate revenue metering early in the design phase of the PGF. Revenue metering equipment shall be installed prior to connecting to the BCTC Transmission System, and its location shall be selected and confirmed during the design stage. The revenue metering shall be in accordance with Measurement Canada regulations and, or compatible with, BC Hydro’s Requirements for Remotely Read Load Profile Revenue Metering, which is available at http://www.bchydro.com/rx_files/services/services10518.pdf. See section 6.2 for possible location.

4.5.5 Dispatching for System Operations and Maintenance

BCTC operates and maintains its system to provide reliable customer service while meeting the seasonal and daily peak loads even during equipment outages and disturbances. New line and generation connections shall not restrict timely outage coordination, automatic switching or equipment maintenance scheduling. Preserving reliable service to all BCTC customers is essential and may require additional switchgear, equipment redundancy, or bypass capabilities at the POI for acceptable operation of the system.

4.5.6 Atmospheric and Seismic

The effects of windstorms, floods, lightning, elevation, temperature extremes, icing, contamination and earthquakes must be considered in the design and operation of the connected facilities. The PG is responsible for determining that the appropriate standards, codes, criteria, recommended practices, guides and Good Utility Practice are met for equipment that they are installing.

4.5.7 Physical Security

The potential vulnerability of the facility to sabotage or terrorist threat should be factored into the design and operating procedures. The PG is responsible for determining that the appropriate standards, codes, criteria, recommended practices, guides and Good Utility Practice are met for equipment that they are installing.

4.6 Transmission and Substation Facilities

Some new connections to the BCTC System may require that one or more BCTC lines (a transmission path) be looped through the PG’s facilities, or sectionalized with the addition of switches. The design and ratings of these facilities shall not restrict the capability of the line(s) and BCTC’s contractual transmission path rights.

4.7 Insulation Coordination

Power system equipment is designed to withstand voltage stresses associated with expected operation. Adding or connecting new facilities can change equipment duty, and may require existing equipment be replaced or new switchgear, telecommunications, shielding, grounding and/or surge protection be added to control voltage stress to acceptable levels. Interconnection studies shall include the evaluation of the impact on equipment insulation coordination. BCTC may identify additional requirements to maintain an acceptable level of BCTC System availability, reliability, equipment insulation margins and safety.

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Voltage stresses, such as lightning or switching surges, and temporary over-voltages may affect equipment duty. Remedies depend on the equipment capability and the type and magnitude of the stress. In general, stations with equipment operated at 15 kV and above, as well as all transformers and reactors, shall be protected against lightning and switching surges. Typically, this includes station shielding against direct lightning strikes, surge arresters on all transformers, reactors, and surge protection with arresters on the incoming lines.

When new equipment is connected to the BCTC System, they shall not degrade existing BCTC System operating performances and capabilities. Generally, in order to avoid potential problems, components for the new system shall have lightning, switching and temporary over-voltage performances that are comparable to the existing BCTC System.

Each substation shall have a ground grid that is solidly connected to all metallic structures and other non-energized metallic equipment. This grid shall limit the ground potential gradients to such voltage and current levels that will not endanger the safety of people, or damage equipment, which are in or immediately adjacent to the station under normal and fault conditions. The ground grid size and type are in part based on local soil conditions and available electrical fault current magnitudes. In areas where ground grid voltage rises beyond acceptable, safe limits (for example due to high soil resistivity or limited substation space), grounding rods and grounding wells might be used to lower the ground grid resistance to limit station ground potential rise to below 5 kV.

BCTC lines are typically not shielded from lightning, and the tower footing resistances can be much larger than those normally encountered for shielded lines. For security reason, most lines have (10s) reclose feature while EHV lines have possibility for high-speed (0.5-1.0s) reclose. Also, some lines on the BCTC System are insulated for future use at a higher system voltage than present operation. For example, a 230 kV line may be built to 500 kV standards. Connections to these lines shall be designed and insulated with the ultimate usage taken into account. Some equipment in the station such as transformers, surge arresters and circuit breakers may be rated for the actual operating voltage but special attention shall be given to insulation coordination in consideration of the higher surges that the line can deliver to the station.

All BCTC stations are fully shielded while line shielding over short distances from the station are applied on lines operated at 230 kV and above. Furthermore, since BCTC line insulation levels are typically higher than line entrance equipment, surge arresters are applied at the line terminals to limit incoming lightning and/or switching over-voltage surges.

4.7.1 Lightning Surges

If the PG proposes to tap a shielded transmission line, the tap line to the PGF substation shall also be shielded. For an unshielded transmission line, the tap line does not typically require shielding beyond what is needed for substation entrance. However, special circumstances such as the length of the tap line may affect shielding requirements.

All lines that terminate at BCTC substations shall have station entrance surge protection while those at 230 kV and higher require short lengths of shielding from station with compatible tower footing resistances. (See section 5.3.2 for line shielding requirements for lines entering BCTC stations.)

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4.7.2 Switching Surges

EHV lines and stations rated above 300 kV require attention to switching surge voltages in their design. BCTC will provide information on the specifics of switching surge voltage for particular locations upon request.

4.7.3 Temporary Over-voltages

Temporary over-voltages can last from seconds to minutes, and are not characterized as surges. These over-voltages are present during islanding, faults, loss of load, or long-line situations. All new and existing equipment shall be capable of withstanding these duties.

The standard system voltages are as shown in the Table 1 below.

Table 1: System Voltages

Nominal Voltage (kV RMS, L-L)

Normal Maximum Voltages (kV RMS, L-L)

60, 66 72.5 132, 1382 145

230 253 287 315 360 396 500 550

4.7.4 Neutral Shifts

When generation is connected to the low-voltage, grounded wye side of a delta-grounded wye (Δ-YG) transformer as may occur due to the addition of on-site generation to an existing load, opening the remote line terminal connection due to unbalanced fault clearing may cause over-voltages on the high-voltage terminal. These over-voltages can affect personnel safety and damage equipment. This type of over-voltage is commonly described as a neutral shift and can increase the voltage on the un-faulted phases to 1.73 per unit or higher if there is significant line capacitance. At this voltage, the equipment insulation withstand duration can be very short. Several alternative remedies to avoid neutral shift and its potential problems are possible. The following describes three possible solutions acceptable to BCTC.

a) Effectively Grounded System

An effectively grounded system is defined as a system with X0/X1 ≤3.0 and R0/X1 ≤1.0. An effectively grounded system will minimize the risk of damage to surge arresters and other connected equipment. Utilizing appropriate transformer connections on the high-voltage side will make the system effectively grounded. Transformer connections typically used to obtain an effective ground on the high-voltage side of a transformer include the following:

2 Both 132 and 138 kV are used as the nominal voltage for studies in different locations of the system for historical reasons. Voltages, impedances, and fault levels are stated on the basis of the nominal voltage. Both can be correctly characterized as within the 138 kV voltage class.

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A transformer with the transmission voltage (BCTC) side connected in a YG configuration and low-voltage side in a closed Δ.

A three winding transformer with a closed Δ tertiary winding and both the primary and secondary sides connected YG.

Installation of a grounding transformer on the high-voltage side.

b) Increase Insulation Levels

Rate the insulation of equipment connected to the transmission line high-voltage side to be able to withstand the expected amplitude and duration of the neutral shift. Switchgear that interrupts faults or load supplied from a Δ connected transformer winding shall be capable of withstanding increased recovery voltages. Increased insulation would also need to be applied at the remote line terminals and any stations tapped to the line.

c) High Speed Separation

Rapidly separate the back-feed source from the step-up transformer by tripping a breaker using either remote relay detection with pilot scheme (transfer trip) or local relay detection of the over-voltage condition. In general, it is not acceptable to disconnect the PGF after the line terminals have already opened due to considerations of surge arrester thermal and equipment insulation withstand capability.

4.8 Substation Grounding

Each substation shall have a ground grid that is solidly connected to all metallic structures and other non-energized metallic equipment. This grid shall limit the ground potential gradients to such voltage and current levels that will not endanger the safety of people, or damage equipment, which are in or immediately adjacent to the station under normal and fault conditions. The ground grid size and type are in part based on local soil conditions and available electrical fault current magnitudes. In areas where ground grid voltage rises beyond acceptable, safe limits (for example due to high soil resistivity or limited substation space), grounding rods and grounding wells might be used to reduce the ground grid resistance to acceptable levels.

If a new ground grid is close to another substation, the two ground grids may be isolated or connected. If the ground grids are to be isolated, there shall be no metallic ground connections between the two substation ground grids. Cable shields, cable sheaths, station service ground sheaths and overhead transmission shield wires can all inadvertently connect ground grids. Fibre-optic cables are highly preferable for providing telecommunications and control between two substations while maintaining isolated ground grids. If the ground grids are to be interconnected, the interconnecting cables shall have sufficient capacity to handle fault currents and control ground grid voltage rises. Any connection to a BCTC substation ground grid must be approved by BCTC.

New interconnections of transmission lines and/or generation may substantially increase fault current levels at nearby substations. Modifications to the ground grids of existing substations may be necessary to keep grid voltage rises within safe levels. The interconnection studies will determine if modifications are required.

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The ground grid shall be designed to applicable CSA, and IEEE Standards relating to safety in substation grounding.

4.9 Inspection, Test, Calibration and Maintenance

Transmission elements (e.g. lines, line rights of way, transformers, circuit breakers, control and protection equipment, metering, and telecommunications) that are part of the proposed connection and could affect the reliability of the BCTC System need to be inspected and maintained in conformance with regional standards and Good Utility Practice. The PG has full responsibility for the inspection, testing, calibration, and maintenance of their equipment, up to the location of change of ownership or POI as applicable. Transmission Maintenance and Inspection Plan (TMIP) requirements are a portion of the WECC Reliability Management System for Transmission. The PG or utility may be required by WECC to annually certify that it has developed, documented, and implemented an adequate TMIP.

4.9.1 Pre-energization Inspection and Testing

The PG is responsible for the pre-energization and testing of its equipment.

For equipment that can impact the BCTC System, the PG shall develop an Inspection and Test Plan for pre-energization and energization testing. BCTC may request to review the test plan prior to the test(s). BCTC may require additional tests. The PG shall make available to BCTC, upon request, all drawings, specifications, and test records of the POI equipment. Also upon request, BCTC will make available to the PG similar documents describing the BCTC POI equipment.

4.10 Station Service

Power that is provided for local use at a substation to operate lighting, heating and auxiliary equipment is termed station service. Alternate station service is a backup source of power, used only in emergency situations or during maintenance when primary station service is not available.

Station service power is the responsibility of the PG. The station service requirements of the new facilities, including voltage and reactive requirements shall not impose operating restrictions on the BCTC System.

Appropriate providers of station service and alternate station service are determined during the interconnection study and planning process, including Project Requirements Diagram development and review.

4.11 Black Start Capability

Black Start capability is the PG’s capability to self start its generation plant in isolation from the transmission system and to pick up part of BCTC System under islanding conditions. If Black Start capability is needed, BCTC will advise the PG at the time of interconnection studies.

If the PGF is not equipped with the self start capability, the PG shall take appropriate design measures to ensure that the PGF can be energized from the BCTC System without causing

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unacceptable performance to BCTC System and the PGF. In particular, the PGF shall ensure that energization of the interconnection transformer to the BCTC System will not result in voltage sags at the POI that exceed the limits specified in section 5.2.3 Table 2. Please consult the IEEE technical paper “Assessing and Limiting Impact of Transformer Inrush Current on Power Quality”, IEEE Transactions on Power Delivery, Vol. 21, No.2, April 2006.

4.12 Synchronizing Facilities

Automatic synchronizing relays typically contain frequency, voltage, slip and phase angle matching elements, and breaker close compensation. These elements shall be set to assure orderly synchronization to the BCTC System. If there is a possibility of the two systems being tied together where a parallel path already exists, then the scheme shall be augmented with a synchro-check relay.

All automatic synchronization shall be supervised by a synchronizing check relay, IEEE device 25. This is to ensure that the generator is not connected to the energized power system out of synchronization.

4.13 Certification of the Power Generating Facility

A Professional Engineer, registered in the Province of British Columbia, must declare that the PGF has been designed, constructed and tested in accordance with:

The interconnection requirements stated in this document,

The project specific requirements as stated by BCTC,

Good Utility Practice, and

Applicable standards.

All reports, drawings, equipment specification and modelling data of technical nature (excluding manufacturing drawings) shall be stamped by a Professional Engineer registered in the Province of British Columbia.

4.14 PGF Modelling and Data Requirements

The PG shall provide complete models for each component of the PGF. The models and their associated data shall be validated in accordance with Appendix D – Data Requirements.

5. Performance Requirements

The following performance requirements can be satisfied by various methods. It is the responsibility of the PG to provide the appropriate documentation and/or test reports to demonstrate compliance.

5.1 Electrical Disturbances Requirement

The PGF shall be designed, constructed, operated and maintained to meet the requirements specified in this document, all applicable laws, regulations, reliability requirements and standards with respect to the following characteristics:

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Electric system disturbances that produce abnormal power flows,

Over-voltages and under-voltage,

Over-frequency and under-frequency,

Resonance,

Power system faults and equipment failures,

Audible noise, radio, television and telephone interference,

Power system harmonics, and

Other disturbances that might degrade the reliability of the interconnected BCTC System.

5.2 Power Quality

5.2.1 Self Excitation and Resonance Phenomena

The PG shall assess the risk of self-excitation of machines and implement appropriate design measures to protect the PGF as required. Unbalanced faults on the transmission system shall be included in the risk considerations.

The PG shall work in consultation with BCTC to determine an appropriate solution. BCTC will provide the PG with harmonic impedance characteristics at the POI on request.

The PG shall ensure that any issues related to resonance and self-excitation are addressed in the PGF design stage.

5.2.2 Power Parameter Information System

BCTC requires that a Power Parameter Information System (PPIS) to be installed at the PGF to ensure proper power quality is maintained for on-line, off-line, steady and dynamic states. The PPIS is capable of high-speed sampling to capture information such as harmonics, and voltage and current levels. The information captured will allow BCTC and PG staff to assess the condition of electricity generating from the PGF.

See Appendix C – Power Parameter Information System for details.

5.2.3 Voltage Fluctuations and Flicker

Voltage flicker is a momentary increase or decrease in voltage, normally associated with fluctuating load. The characteristics of a particular flicker problem are determined by the nature of the load change. Voltage flicker may arise during the start-up of an induction generator, motor, energization of a transformer, or other equipment where a large inrush of starting current may cause the local system voltage to drop considerably. The PG shall take steps to minimize flicker problems caused by their system.

Specifically, to prevent voltage fluctuations from causing serious disturbances and risks to equipment owned by others that are connected nearby to the Transmission System, the PG shall ensure that:

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Phase-to-phase and phase-to-ground 60 Hz root mean square (RMS) voltage change shall not exceed +5% and -6% compared to the immediately preceding one second average value where:

The value, which is compared to the preceding one-second value, is the RMS value calculated over any ½ 60 Hz cycle.

The limits for acceptable voltage fluctuations at the Point of Interconnection are as shown in Table 2:

Table 2: Voltage Fluctuations

Voltage Change Maximum Rate of Occurrence

+/-3% of normal level once per hour

+5/-6% of normal level once per 8-hour work shift

Exceeding +5/-6% pre-scheduled by BCTC

Voltage dips more frequent than once per hour shall be limited to the “Border Line of Visibility Curve” contained in Appendix F (IEEE Standard 519), Permissible Voltage Dips – Border Line of Visibility Curve.

5.2.4 Voltage and Current Harmonics

Harmonics can cause telecommunications interference and thermal heating in transformers; they can harm solid state equipment and create resonant over-voltages. To protect equipment from damage, harmonics shall be managed and mitigated. The PG’s equipment shall not cause voltage and current harmonics on the Transmission System to exceed the limits specified in IEEE Standard 519. Harmonic distortion is defined as the ratio of the root mean square (RMS) value of the harmonic to the RMS value of the fundamental voltage or current. Single frequency and total harmonic distortion measurements may be conducted at the POI, the generation site, or other locations on the Transmission System to determine whether the PG’s equipment is the source of excessive harmonics.

5.2.5 Phase Unbalance

Unbalanced phase voltages and currents can affect protective relay coordination and cause high neutral currents and thermal overloading of generators and motors. To protect equipment of BCTC, BC Hydro and third-parties, the PGF’s contribution to the total unbalances at the POI shall not cause a voltage unbalance greater than 1% or a current unbalance greater than 5%. Phase unbalance is the percent deviation of one phase from the average of all three phases.

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5.3 Station and Switchgear

5.3.1 General

Circuit breakers, disconnect switches, and all other current carrying equipment connected to the Transmission System shall be capable of carrying normal and emergency load currents without damage. Only a circuit breaker (CB) will be acceptable as an interrupting device, for protection initiated tripping at PGF.

5.3.2 Station Insulation Requirements

In general, stations with equipment operated at high voltages must be protected against lightning, switching surges and temporary over-voltages. To achieve acceptable performance and minimize costs, insulation coordination studies shall be conducted.

Station lightning protection includes shielding of station equipment from direct lightning strikes and protection from incoming transient voltage surges on lines connected to the station. Typically, this includes:

Station shielding using shield wires and/or masts,

Short line overhead ground wire shielding for the first two spans outside the station,

Surge arresters and surge capacitance (Capacitive Voltage Transformers) on incoming lines, and

Dedicated surge arresters on major equipment with insulation systems that are subject to damage, such as transformers, reactors and GIS.

Short line shielding reduces fast front and large magnitude surges from strikes beyond the shielded section due to corona distortion of the propagated wave within the shielded section. The line terminal surge capacitance further decreases the voltage surge front and vastly improves the surge arrestor’s ability to limit over-voltages.

Lines constructed for future operation as a higher system voltage merit special attention to these insulation coordination issues.

Switching transients require coordinated designs to protect station equipment from external surges coming into the station on lines and from surges created in the station itself during switching operations. Above 300 kV, some method(s) of limiting switching transients are usually required to achieve acceptable line switching performance by circuit breakers that are used to energize or reclose lines.

Temporary over-voltages (TOV) can occur during fault clearing or switching in the BCTC System due to high ground impedances during the isolation of faulted subsystems, where the neutral has shifted and/or by system resonance conditions. The severity of TOV is usually estimated by simulations. Station equipment, including surge arresters suitable for TOV expected during system operating conditions, must be selected. It may be necessary to constrain some operating conditions to achieve reliable and economical system design.

The transmission line lightning insulation level and line terminal station equipment insulation levels for BCTC voltage classes are listed in Table 3 and Table 4 below.

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Table 3: BCTC Unshielded Transmission Line Lightning Insulation Levels

(Note: Lines are unshielded except for short lengths from station.)

Voltage Class (line to line kV)

Lightning Critical Flashover

(CFO) (crest kV)

Shielding @ Station Minimum Number of

Spans

Shielded Section Line Tower

Footing R max (Low Frequency)

69 525 0

138 860 0

230 1265 2 (~0.5 km) 10 ohms

287 1345 2 (~0.5 km) 10 ohms

360 1665 2 (~0.5 km) 15 ohms

500 1985 2 (~0.5 km) 20 ohms

Table 4: BCTC Line Terminal/Station/TX Equipment Ratings (BIL and SIL)

(Note: Lines are unshielded except for short lengths from station.)

Terminal/Station/TX Equipment Line/Station

Surge Arrestors Voltage Class (line to line kV)

BIL (kV) SIL (kV) V-rating IEC-Class

Capacitance CCVT

(nf minimum)

69 350/350/350 ~290/290/290 72/60 2 10

138 650/550/550 ~540/450/450 144/120 3 10

230 950/950/850 850/850/750 228/192 3 10

287 1050/1050/950 950/950/850 240/228 4 10

360 1300/1300/1175 1050/1050/950 300/288 4 10

500 1550/1550/1550 1175/1175/1175 396/396 5 10

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5.3.3 Clearances

Energized parts shall be maintained at safe vertical and horizontal clearances that are compliant with the Canadian and British Columbia standards including WorkSafeBC’s requirements.

5.3.4 Circuit Breaker Requirements:

All circuit breakers installed at the generation site, the interconnecting substation, the Point of Interconnection, or any other location on the Transmission System shall have:

An interrupting rating equal to or higher than the fault duty at the specific location as determined by BCTC,

An ability to meet BCTC’s “ultimate” fault duty for the location. If the CB supplied has a lower interrupting rating, the PG assumes the responsibility for upgrading when necessary to accommodate changes to the system. The PG is responsible for contacting BCTC when system changes occur to ensure their equipment is suitably rated,

A stated interrupting capability that does not rely on fault reduction schemes such as intentional time delays in clearing,

An ability to perform all required switching duties, including but not limited to capacitive current switching (line/cable dropping in particular), load current switching, and out-of-phase opening, and

An ability to perform all required duties without creating transient over-voltages that could damage equipment of BCTC, BC Hydro or third-parties.

5.3.5 Circuit Breaker Rated Interrupting Times and Fault Clearing Times

Table 5 specifies the rated interrupting times required of circuit breakers on the Transmission System. These times apply to HV entrance circuit breaker whether at the Generation Site and/or the Point of Interconnection. Expected multi-phase fault clearing times with telecommunications assisted protection are also stated in Table 5.

Table 5: Circuit Breaker Rated Interrupting Times and Multi-phase Fault Clearing Times for

Telecommunications assisted Lines

Nominal Voltage Class Rated Interrupting Time (Cycles)

Expected multi-phase Fault Clearing Times (Cycles)

287 kV – 500 kV 2 3 – 4 230 kV 3 5 – 6

115 kV – 161 kV 3 5 – 8 60 kV and below 5 7 – 11

Delayed clearing due to breaker failure can be up to 8 cycles longer than the times stated in Table 5.

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5.4 Generators

The PGF shall comply with codes, standards and rules applicable in BC including NERC/WECC Planning Standards Sections II.B (System Modeling Data Requirements, Generation Equipment) and III.C (System Protection and Control, Generation Protection and Control). The generators shall be designed in accordance with all applicable standards and the following requirements.

5.4.1 Generator Active Power

The active power output should be limited to Rated Power (MVA rating times rated overexcited power factor).

5.4.2 Generator Reactive Power Requirements

All synchronous generators shall have the ability to operate continuously in a range from an over-excited power factor of 90% to an under-excited power factor of 95% over the generating unit’s complete range of output power.

All synchronous generators shall have the ability to operate continuously at their Maximum Power Output (MPO) and at rated field current while at any terminal voltage level within plus 5% and minus 5% of rated terminal voltage.

All synchronous generators shall have the ability to follow a specified voltage or VAR schedule issued on an hourly, daily, or seasonal basis dependant upon the location of the generator. BCTC will specify the desired generator voltage setting or desired MVAR output level for each generator. The generator may be required to change its MVAR output or voltage reference set point from time to time depending on system conditions and the location of the generator. If the BCTC system operator does not have direct control over the generator's voltage regulator via supervisory control, the PG's operator shall be able to implement the new MVAR output or voltage reference set point within an agreed time.

All synchronous generators shall have the ability to operate for periods of at least 30 seconds at any generator terminal voltage level between 0.70 pu and 1.20 pu with the main circuit breaker open to allow the open circuit saturation test to be conducted, for each generator and its auxiliary equipment.

5.4.3 Generation Excitation Equipment Requirements

Synchronous generator excitation plays an important role in ensuring electric system stability and reliability. It shall be coordinated with generation protection to minimize generator tripping during disturbance-caused abnormal voltage and current conditions. Excitation equipment shall comply with industry best practices and applicable industry standards for synchronous generator excitation equipment. Excitation equipment including the exciter, Automatic Voltage Regulator, Power System Stabilizer and over-excitation limiter shall meet NERC and WECC standards, and the following requirements:

The excitation used shall be of the “High initial response type” as defined by IEEE Standard 421.4.

The excitation shall be able to attain 95% of the difference between the available ceiling voltage and rated load field voltage in 0.1 second or less.

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The excitation ceiling voltage, defined as the maximum exciter voltage attainable under initial conditions of generator rated MVA, rated power factor, rated terminal voltage and rated speed, shall be greater than 3.0 times rated field voltage.

The excitation system shall have a negative ceiling voltage capability.

The excitation system shall be able to produce the field current required for continuous operation at generator rated MVA, rated power factor, 1.10 times rated terminal voltage and rated speed (“Excitation System Rated Current”).

The excitation system shall be able to provide 1.6 times the excitation system rated current for 30 seconds (“exciter overload current rating”).

The PG shall provide a copy of all excitation system controls, limiters, and protective equipment settings to BCTC.

a) Automatic Voltage Regulator

The synchronous generator exciter shall be equipped and operated with an Automatic Voltage Regulator (AVR) set to control the generator terminal voltage. BCTC may request connection of the voltage regulator line drop compensation circuit to regulate a virtual location 50-80% through the step-up transformer reactance.

The AVR shall be capable of automatically maintaining the generator steady state terminal voltage, without hunting, to within plus or minus 0.1% of any set point. The set point range shall be a minimum of from +20% to -30% of the rated terminal voltage of the generator. This control range is for testing purposes only. The generator and excitation equipment are not required to be capable of continuous operation at these extreme terminal voltage levels.

b) Excitation System Limiter

Excitation limiters shall be coordinated with the generator protective relay settings and shall meet the following requirements:

Limiter settings shall not restrict the generator’s operating range (terminal voltage and MVAR limits) to less than 100% of the continuous capability of the equipment.

Limiters shall be able to control the exciter output to avoid unnecessary operation of the generator’s protective relays in the event of any sudden abnormal system condition.

Limiters shall be instantaneous reset. The output of each limiter shall immediately return to zero when its input returns to zero.

Limiters shall not switch the excitation system from automatic to manual voltage control.

c) Power System Stabilizer

A power System Stabilizer (PSS) shall be provided for the synchronous generator according to WECC requirement. The PG shall provide BCTC with information on the type and model of PSS for each generator. BCTC will conduct studies at the PG’s cost to determine the optimum PSS settings that will be implemented and confirmed by field tests during the commissioning of each generator.

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5.4.4 Governor Requirements

Governors shall comply with Section 4 of IEEE Standard 125 "IEEE Recommended Practice for Preparation of Equipment Specifications for Speed Governing of Hydraulic Turbines Intended to Drive Electric Generators" and with Section 4 of IEEE Standard 122 "IEEE Recommended Practice for Functional and Performance Characteristics of Control Systems for Steam Turbine-Generator Units.” Similar performance requirements shall apply to all types of Prime Movers (including reciprocating combustion engines and gas turbines). In addition, the governor shall:

Have speed governors installed on the prime movers of all generators;

Have governor droops set at 5%,

Have governor dead-bands not to exceed +/-0.056 Hz, and

Be capable of providing immediate and sustained response to abnormal frequency excursions.

5.4.5 Voltage and Frequency Operation during Disturbances

Power system disturbances due to system events such as faults and forced equipment outages expose connected generators to oscillations in voltage and frequency. It is important that lines and generators remain in service during those transient oscillations that are stable and damped. Over/under voltage and over/under frequency relays are normally installed to protect the generators from extended off-nominal operation. To ensure that the PG’s generator is not tripped prematurely, the required time delay settings for such relays shall not encroach upon the off-nominal frequency described in (a) and the off-nominal voltage limits describe in section (b) below. As well, PGF quality protection (described in section 6.4) shall not encroach upon the operating limits described in (a) and (b) below.

a) Frequency

Each generator shall be capable of continuous operation at 59.5 to 60.5 Hz and of limited time operation at a larger frequency range. If the system frequency declines and governor action is not able to stop the decline, loads are automatically interrupted in discrete steps. This load interruption (load shedding) within the interconnected system is designed to stabilize the system frequency by balancing the amount of generation and load.

Generators shall remain connected to the system during frequency excursions, both to limit the amount of load shedding required and to help the system avoid a complete collapse. Over/under frequency relays are normally installed to protect the generators from operation beyond the safe periods of off-nominal frequency range. BCTC will specify the minimum required time. All generators shall meet the minimum criteria listed in Table 6 and Table 7. During off-nominal frequency excursions, typical hydro generators are expected to have capabilities beyond those listed in Table 6. Where the requirements are not met, PG shall arrange for equivalent load shedding for the corresponding generation tripping.

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Table 6: Off-Nominal Frequency Minimum Performance

Under-frequency Limit Over-frequency Limit Minimum Time 60.0-59.5 Hz 60.0-60.5 Hz Continuous

59.4-58.5 Hz 60.6-61.5 Hz 3 minutes

58.4-57.9 Hz 61.6-61.7 Hz 30 seconds

57.8-57.4 Hz 7.5 seconds

57.3-56.9 Hz 45 cycles

56.8-56.5 Hz 7.2 cycles

Less than 56.4 Hz Greater than 61.7 Hz 0 cycles

Off-nominal frequency requirements are described in detail in WECC document entitled, “WECC Coordinated Off-Nominal Frequency Load Shedding and Restoration Plan.”

Generators that participate in “Local Island” conditions as described in section 8.3 may have specific off-nominal frequency requirements, which BCTC will specify.

As well as the under and over-frequency relays applied as part of generator protection, power quality protection (described in section 6.4) must also coordinate with these limits of operation.

b) Voltage

Each generator shall be capable to ride through the disturbances and operate continuously at between 0.90 and 1.10 pu terminal voltage. In certain areas of the Transmission System, under-voltage load shedding protection is used to avoid voltage collapse. The PGF under-voltage relay settings shall have delays that coordinate with the existing under-voltage load shedding program. BCTC will specify the minimum required time delays.

The nominal voltage levels available for connecting to Transmission System depend on the location of the PGF. Normal operating voltages on Transmission System can vary by up to +/-10% of nominal voltage levels and may vary over a wider range at certain locations or during abnormal or emergency conditions. BCTC will specify the nominal voltage levels.

Table 7 below describes the off-nominal voltage performance limits.

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Table 7: Off-Nominal Voltage Minimum Performance

Over-voltage Under-voltage Minimum Delay

<1.10 pu >0.90 pu Continuous - ≤0.90 pu 10.0 seconds

≥1.10 pu - 5.0 seconds

≥1.20 pu ≤0.80 pu 2.0 seconds

≥1.25 pu ≤0.75 pu 0.8 seconds

≥1.30 pu - 0 seconds

5.4.6 Contingency and RAS Requirements

The PG is responsible for determining and adequately designing and protecting its generating plant against the impacts of switching operations and contingencies in the Transmission System such as:

Load rejections will cause over-speed and over-voltages on the PGF. The amount of over-speed and over-voltage will be a function of the electro-mechanical and system parameters of the interconnected system and the PGF.

Self-excitation can occur when an islanded or unloaded transmission system, which, if left connected to the PGF, presents a capacitive load in excess of the synchronous generator's capability to absorb it. The PGF could be damaged by the resulting over-voltage if the PGF is not quickly disconnected from the transmission system. BCTC will provide data on the maximum line capacitive admittance for line sections that may be left connected to the PGF by switching events.

Resonance or near resonance may occur when an islanded transmission system is left connected to the PGF. This will cause unacceptably high transient over-voltages unless corrective measures are provided.

To prevent the PGF from being damaged by reclosing operations, the PGF will be disconnected from the Transmission System prior to BCTC reclosing the circuit.

Acceleration of the PGF during faults on nearby transmission lines could cause the plant to slip out of synchronism from the transmission system. BCTC will take measures to reduce the probability of such events but if a loss of synchronism occurs, it is the responsibility of the PG to detect the loss and immediately trip off the affected generators.

Remedial Action Schemes may be required to mitigate the impacts of contingencies to the Transmission System, e.g., generation shedding, generation run-back, etc.

5.5 Transformer Requirements

The PG shall coordinate transformer ratio and tap settings with BCTC to optimize the reactive power capability (lagging and leading) that can be provided to the Transmission System. Refer to IEEE Std. C57.116, Guide for Transformers Directly Connected to Generators for guidance. BCTC will provide the expected normal operating voltage range at the POI to

28 OCTOBER 10, 2008

assist in ratio selection. The ratio should not be based solely on the nominal voltage or the voltage class of the POI.

The Transmission System must normally be effectively grounded. This requires all PGFs connect to the Transmission System via transformers to have solidly grounded HV windings and with transformers configured so that the HV winding is an effective source of zero sequence current. A HV grounded wye to LV delta is the conventional optimum configuration. (See section 4.4 for more details) Other transformer winding configurations such as auto-transformers may be necessary and appropriate where there is an underlying collector network and the POI has suitable network switching to permit selective system protective relaying.

Transformers, their auxiliaries, controls, protection and operating procedures shall allow the generator to deliver its continuous reactive power capability. Transformers shall also be able to withstand the voltage and frequency excursions associated with load rejection and system separation events.

BCTC recommends generator step-up transformers to have off-load taps on the secondary (HV side) with a minimum range of two 2.5%-steps above and two 2.5%-steps below the normal delivery voltage. BCTC must approve the selected voltage, winding connections, and adjustment range for each interconnection.

5.6 Transmission Line Design Requirements

Transmission line designs shall meet or exceed the following requirements to ensure no adverse impact on the Transmission System:

The latest version of CSA Standard CAN/CSA C22.3 No. 1, Overhead Systems

BCTC’s Engineering Standards3 for Overhead Transmission Lines

BCTC’s practice for structure design load factors and weather loading factors

The PG shall identify the Professional Engineer of Record responsible for the design.

Although there is no requirement on either BCTC or BC Hydro to take over ownership and operation of a PG line connecting to the BCTC System, there may be circumstances which warrant such a transfer of assets. For a transfer of ownership of a transmission line, BCTC may, at its discretion, impose additional technical and non-technical requirements and submittals above and beyond those detailed in the subsections below and this document in general.

5.6.1 Environmental Considerations

Construction of transmission lines shall be performed in an environmentally responsible manner in accordance with the following key commitments of BCTC’s Environmental Responsibility Principles and the Environmental Management System (EMS):

Avoid and mitigate environmental impacts.

Meet or exceed environmental regulatory requirements.

3 BCTC has adopted and utilizes BC Hydro Engineering “41” Series Transmission Engineering Technical Standards, Procedures and Guidelines

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BCTC expects that if environmental incidents occur they shall be mitigated in a duly diligent fashion. An environmental assessment is required and an Environmental Management Plan, which has been agreed with the appropriate regulatory agencies, is required before construction commences.

5.6.2 Connection to the BCTC System

The constructed transmission line is subject to the following requirements prior to acceptance by BCTC for connection to the Transmission System:

Approval by the Electrical Inspector or the Authority Having Jurisdiction,

Inspection of transmission line by BCTC,

Defects identified by inspection shall be corrected prior to acceptance, and

Assurance by the named Professional Engineer of Record that the constructed transmission line complies with the design.

5.6.3 Line Performance

a) Single Circuit Connection

Depending on network topology and PGF size, acceptable line performance can be achieved to avoid generators separating from the system by applying the following:

Shielding to the transmission line,

Line surge arrestors, and/or

Single-pole reclosing line protection.

Acceptable line performance means similar to line performance to lines constructed for similar purpose in the same voltage class of network transmission lines in the region.

b) Multiple Circuit Connection

There is a possibility of simultaneous or near simultaneous faults from lightning strikes where multiple circuits share a common right-of-way. Therefore, shielding, line arresters or single-pole reclosing protection shall be applied.

6. Protection Requirements

6.1 General Requirements

6.1.1 Internal Fault Protection

The PGF’s protection shall have adequate sensitivity to detect and clear all electrical faults in the PGF, and shall coordinate with other BCTC protection systems for the present and future (ultimate) fault levels. This protection is generally referred to as “Entrance Protection”. Coordination is defined as either:

30 OCTOBER 10, 2008

Fully selective clearing, in which the PGF’s protection clears all faults in the PGF before other relaying within the Transmission System initiates tripping for such faults, or

Simultaneous clearing, in which the PGF's protection clears all faults in the PGF simultaneously with the clearing of such faults by Transmission System protection.

Fully selective clearing is normally required for PGF. However BCTC may require simultaneous clearing in certain cases to meet the protection requirements of the Transmission System.

6.1.2 Equipment Rating

The PG's equipment shall be rated to carry, detect and interrupt the present and future fault levels at the PGF. To do this, the PG's station and transmission equipment facilities, including but not limited to all current transformers, potential transformers, secondary cabling, DC system/battery charger, switchboard wiring and protective relays, shall be designed for the ultimate fault duty. (See sections 4.4, and 5.3.4 for further details.)

6.1.3 Unbalance, Under-frequency and Under-voltage

The PG's equipment may be subjected to negative sequence current due to unbalances on the Transmission System. BCTC recommends the provision of negative sequence (unbalance) protection (device 46) to protect rotating equipment from excessive and potentially damaging negative sequence current arising from voltage unbalance.

Relays shall be based on solid state or microprocessor technology and shall have a dropout time of 2 cycles or less. The PG shall coordinate their settings with BCTC (WECC) requirements.

Under-voltage conditions may occur during emergencies or abnormal operating situations on the Transmission System. The PG is encouraged to use timed under-voltage-tripping (device 27) to protect their equipment. This protection must also be coordinated with the requirements in section 5.4.5.

6.2 Entrance Protection

The PGF entrance circuit breaker shall be included in the entrance protection zone. That is, the relays shall connect to current transformers on the Transmission System side of the circuit breaker, as shown in Figure 5.

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Figure 5: Generic Entrance Protection One-Line Diagram

BCTC SYSTEM

POSSIBLE REVENUE METERING LOCATIONS

MANUAL GROUP OPERATED DISCONNECT PROVIDED BY PG ACCESSIBLE TO BCTC AND CAPABLE OF BEING SECURED BY A STANDARD SYSTEM PADLOCK.

K

ENTRANCE PROTECTION

All PG’s metering equipment shall be included in the entrance protection zone or in the PGF’s internal protection zones. No revenue metering equipment shall be located on the Transmission System side of the entrance protection zone unless by special arrangement with BCTC.

Figure 6 describes an example installation that meets the minimum requirements for entrance protection.

Figure 6: Entrance Protection Example

K

SUPPLY CONNECTION AS DETAILED IN SECTION 5.3.2

51

87

A

Note that the application of transformer differential protection eases the coordination requirement with protection in the BCTC System.

6.3 Transmission Line Protection Requirements

The PG shall provide redundant equipment to detect all phase and ground faults on the Transmission System. Depending on the location and method of connecting to the Transmission System, telecommunications assisted line protection may be required to provide acceptable fault clearing times.

The PG shall provide additional protection to detect faults on the Transmission System. This protection is generally referred to as “Transmission Line Protection.” The required fault clearing times shall be specified by BCTC. BCTC will recommend the required protection. See also section 4.5.3.

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BCTC will define the required protection to protect the BCTC System.

The PG shall provide breaker failure protection for the entrance circuit breaker.

For line protection at the PGF the following shall apply:

For non-pilot schemes protection, BCTC will make recommendations for line protection.

For pilot schemes, BCTC will specify protection schemes.

6.3.1 Detection of Ground Faults

Depending on the PG's transformer winding configuration, possible methods to detect ground faults include the use of:

For detecting zero sequence voltage in the open delta secondary of voltage instrument transformers, a voltage relay (59N), and

For detecting zero sequence current flow from the PGF to the Transmission System, a current relay (51N).

6.3.2 Detection of Phase Faults

The PG shall provide dedicated phase fault protection to clear isolated multi-phase faults on the Transmission System using under-voltage relaying (27), directional inverse time over-current relaying (67), impedance relaying (21), or inverse time over-current relaying (51) as appropriate to the installation.

6.3.3 Breaker Failure Protection of the PGF HV Circuit Breaker

Breaker failure protection shall be provided for failure of the main PGF HV circuit breaker failing to clear transmission line faults.

Breaker failure protection shall take one of the following forms:

CB auxiliary switch scheme,

Current-based scheme, or

Back-up relaying within the PGF.

BCTC does not intentionally provide breaker failure back-up tripping for the case of the main PGF circuit breaker failing to clear PGF facility faults. For situations where telecommunications facilities are applied for other reasons (for example transmission line protection), a spare signal channel may be available to provide back-up tripping. Provision for such a facility will be determined by BCTC and evaluated on a case by case basis.

6.3.4 Prevention of Energization of Ungrounded Transmission Line by PGF

As indicated in section 4.4.1, PGF shall provide a source of ground fault current to the high voltage side. However, for existing installations that are HV delta connected (no source of ground fault current to high voltage side), the PGF shall be disconnected immediately upon de-energization (open ended or loss of ground source) of the BCTC transmission line to

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avoid the transmission line becoming un-grounded. A direct transfer trip from the BCTC end of the transmission line to the PGF is one method to prevent ungrounded operation, which may be costly. A study will be required.

A sample installation of PG’s transmission line protection is shown in Figure 7 below.

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Figure 7: Sample Installation of Minimum Transmission Line Protection

BCTC TRANSMISSION SYSTEM

MANUAL GROUP OPERATED LOAD BREAK DISCONNECT PROVIDED BY PG.ACCESSIBLE TO BCTC AND CAPABLE OF BEING SECURED BY A STANDARD BCTC PADLOCK.

KADDITIONAL ENTRANCE

PROTECTION REQUIRED

SEE APPENDIX C

59N1

367

1 3

125

OPTIONAL DEVICE 46SEE SECTION 10.1.4

46 27

6.4 Power Quality Protection

The PG shall provide under-voltage, over-voltage, under-frequency and over-frequency power quality protection that complies with BCTC and WECC requirements. Duplicate power quality protection may be required.

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The purpose of power quality protection is to ensure quality of power to other customers in case an island is inadvertently formed. It is applied to the HV VTs at PGF. Depending on application and settings, it may prevent islands from being formed if the connected load in the island is significantly different from the connected generation. This application would then possibly meet the requirements of section 5.4.5. If speed of operation is an issue, other measures may need to be taken as described in sections 4.7.3 and 4.7.4.

As well as meeting power quality issues, the protection shall also meet the requirements of the voltage and frequency limit criteria described in section 5.4.5.

6.5 Under-frequency Load Shedding Protection

If PGF become connected as a load for any period of time or require station service, there may be a requirement for under-frequency load shedding. The requirements will generally follow the requirements of the WECC. BCTC will determine the specific requirements in each instance. (See section 5.4.5 for more details.)

6.5.1 Frequency Relay Requirements

Relays with inverse time vs. frequency operating characteristics are not acceptable. Relays shall be based on solid state or microprocessor technology and shall have a dropout time of 2 cycles or less.

6.6 Batteries / Chargers / DC Supplies

Batteries shall be suitable for station applications, having a long life when on float charge with no load cycling. In general, this requires the use of lead calcium batteries.

PG shall ensure that the continuous DC supply voltage rating of any relay or its associated power supply is not exceeded due to sustained over-voltages on the DC supply bus. Common causes of high, sustained over-voltages are:

Battery chargers at their equalize setting,

Battery chargers connected to the DC supply bus without the station batteries, and

Battery chargers set in the constant current charging mode.

If there is any possibility that the DC rating of a relay will be exceeded, a passive voltage regulator of suitable rating shall be applied to each relay to limit the DC voltage to within that relay’s DC rating.

Dual station batteries may be required for power protection and control equipment for PGF connecting to the Main Transmission System if such connections are permitted. BCTC will determine the requirement of dual station batteries at the time of interconnection studies.

The DC supply shall:

Supply power circuit breaker control circuits from dedicated and independently protected DC circuits,

Supply those physically separated protection systems that are intended to back each other up from dedicated and independently protected DC circuits,

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Provide one under-voltage relay, with time delay, to provide an alarm for battery charger failure or loss of AC supply, and

Provide one under-voltage relay with adjustable setting capability in a scheme4 that:

Operates at least 5 VDC above the minimum acceptable voltage to operate the circuit breaker and associated protection and control circuitry,

Operates to shut down the generator and open the HV circuit breaker to disconnect the PGF from the Transmission System, and

Has delayed trip initiation, not to exceed 1 minute, to override temporary voltage dips.

7. Control and Telecommunications Requirements

7.1 Telecommunications

7.1.1 General

Control and telecommunications facilities, including those for protective relaying and Remedial Action Schemes, may be required at the PGF and within the Transmission System for safe and efficient operation of the power system and for the safety of personnel. This may include the upgrade of existing transmission and interconnected facilities. All facilities and equipment defined in the sections 7.1.2, 7.1.3 and 7.1.4 require BCTC approval to ensure that applicable standards and required functionality, reliability, and availability of spares are met. In some cases, specific equipment may be required to ensure compatibility with existing equipment such as Supervisory Control and Data Acquisition (SCADA) and other data monitoring systems. BCTC may modify its control and telecommunications requirements when detailed PG’s equipment information becomes available or changes. All costs to install, maintain and support communication access are the responsibility of the PG.

7.1.2 Telecommunications Media

Telecommunications media alternatives for the PGF may include dedicated or leased metallic wire line circuits, power line carrier, microwave radio, fibre optics, UHF/VHF radio and satellite. When two-way telecommunications media is required, full-duplex (4-wire or equivalent) circuits will generally be used (except for standard voice telephone circuits on wire line, where 2-wire circuits are used).

Whenever metallic pairs are used, appropriate telecommunications entrance protection shall be provided since the station ground potential can rise to hazardous levels above remote ground potential during a power system fault. Telecommunications entrance protection provides safety to personnel, prevents damage to equipment, and allows continuous use of the telecommunications media and the attached equipment during and after power system

4 This under-voltage tripping function is not required if the PGF is manned 24 hours a day. Coordination of the voltage settings and time delays is required between alarming for battery charger failure or loss of ac supply and under-voltage tripping.

37 OCTOBER 10, 2008

faults. This equipment is the responsibility of the PG and shall meet the public carrier and BCTC safety and protection requirements.

If power line carrier facilities are used, appropriate carrier accessories are required. These include wave-traps, line matching units and carrier coupling devices (often CVTs with carrier accessories), both at the PGF and at the BCTC station having the other carrier terminal.

In cases where the connection is a tap into a circuit that has power line carrier operating on it, a wave-trap is required at the tap point on phase/s of the tap, which could otherwise attenuate the existing carrier signal on the BCTC System. In some cases, specialized carrier bypass facilities will be required.

7.1.3 Telecommunications System for Operating Functions

BCTC will specify the type of equipment required, the interface points and other characteristics required at the interconnection study stage. Facilities, which may be required initially or in the future at the PGF, communicating with BCTC's Control Centres for real-time operation of the power system, include:

Digital and/or analog telemetering equipment,

Remote control, to enable dispatching of power,

Status/alarm reporting equipment to satisfy WECC compliance or for contractual obligations

Equipment for generation shedding or other Remedial Action Scheme actions,

Voice telecommunications for operating,

Data telecommunications for access to SCADA equipment,

Telecommunications media for the above, and

Suitable battery and charger systems for the above.

The first two items above are often combined in one or more SCADA Remote Terminal Units (RTUs).

In some cases, a single analog business telephone dial-up line may be used to interrogate the main revenue meter, backup revenue meter, and the PPIS (Power Parameter Information System) equipment. This is achieved by sharing a common telephone line using a balanced telephone line-sharing device.

In order to ensure compatibility of design and operation, BCTC will provide technical requirements to the PG for the telecommunications equipment at the PGF needed to transmit data from PGF to BCTC.

BCTC will not provide High Voltage Telephone Entrance Protection equipment.

7.1.4 Telecommunications System for Teleprotection Functions

Telecommunications assisted protection facilities may be required for power system protection functions at the PGF and between locations affected by the PGF connection. BCTC will specify the type of equipment required, the interface points and other

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characteristics required at the interconnection study stage. The required facilities may include:

Specialized high-speed teleprotection signals for transmission line protection,

Specialized high speed transfer-trip teleprotection signals for functions such as transformer protection, reactor protection, over-voltage protection, circuit overload protection, breaker failure protection, and the initiation of generator shedding or other remedial actions scheme actions,

Telecommunications media for the protection facilities, and for remote access to electronic relays, event recorders and fault recorders (used for the analysis of power system disturbances), and

The battery and charger system for which parameters and size will be determined on a case by case basis. Some systems may be specified as 24V floating or 48V positive ground. The battery reserve will typically be 8 hours for sites with easy access, or 24 hours for sites without easy access.

In order to ensure compatibility of design and operation, BCTC will provide technical requirements to the PG for the telecommunications equipment at the PGF needed to transmit and receive teleprotection signals between the PGF and BCTC.

BCTC will not provide High Voltage Telecommunication Entrance Protection equipment.

8. System Operating Requirements

8.1 Generation Scheduling and Control

Any new generation being integrated into the BCTC System shall adhere to the scheduling requirements in the prevailing tariff under which it takes transmission and ancillary services from BCTC.

BCTC’s Control Centres will be the main operations contact for all entities with generation connected to the BCTC System.

PG is responsible for providing, or causing to be provided, generating schedules to BCTC. The schedule details shall be agreed upon with BCTC’s Control Centres. BCTC Operators may require real time changes from the agreed schedule when necessary to maintain system reliability. The PG will retain final responsibility for the plant.

If the PG’s generation is controlled in real time by BCTC, the PG shall provide full Supervisory Control and Data Acquisition facilities, including alarm monitoring for each generating unit to a BCTC’s Control Centre. If the PG’s generation schedule is dispatched in real time by BCTC, the PG shall provide to a BCTC’s Control Centre direct control or 24 hour telephone access to a continuously manned PG control centre via a dedicated telephone line. Within an agreed time, the manned PG control centre or the remote control facilities provided to BCTC’s Control Centre shall be able to:

Start-up, synchronize and fully load the PG’s available generators (synchronization will normally be accomplished using the generator unit breakers),

Shut down the PG’s on-line generators,

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Setup Remedial Action Schemes at the PGF if it is required to participate in generation shedding or run-back,

Change the output of any of the PG’s on-line generators according to an accepted schedule, and

Change the mode of operation of any of the PG’s generators (e.g., from generating to synchronous condenser mode if the units have the capability.)

8.2 Remote Operations

If the PGF is operated remotely by BCTC’s Control Centres, BCTC will require, in addition to the direct control of the generators listed in Section 8.1, the ability to monitor alarms and operate the PGF’s generator switchyard and transmission system. Detailed requirements will be specified in a separate agreement between BCTC and the PG.

8.3 Generation Islanding

a) Local Islanding

For those generators interconnected to the BCTC System through a tapped transmission line, a local island is created when the breakers at the ends of the transmission line open. This leaves the generator and any other loads that also are tapped off this line isolated from the power system. Delayed fault clearing, over-voltage, ferro-resonance, extended under-voltages, etc., can result from this local island condition and shall not be allowed to persist. Special relays and relay settings are required to disconnect the generator(s) rapidly in the local island. (See sections 5.4.5 and 6.5 for more details.)

Note however a local island could persist as long as PQ and frequency are within acceptable limits.

To protect BCTC System and its customers against these extended voltage and frequency excursions and degraded service, special relays to detect these conditions and isolate the local generation from BCTC are required as per sections 6.4 and 6.5. These relays shall not be set with such short time or too narrow an operating window as to encroach on the frequency and voltage limit operating criteria described in section 5.4.5. For cases where the requirements conflict, other measures may need to be taken such as direct transfer tripping form the BCTC source station(s) to the PGF.

b) Large Area Islanding

Area Islanding is a condition where the power system splits into large areas of isolated load and generation groups, usually when breakers operate for fault clearing or in a Remedial Action Scheme for system stability. Generally, the “islanded groups” will not have a stable load to generation resource balance. Protective relaying that responds to large frequency and voltage fluctuations may trip the loads and/or generators during an islanding condition after a disturbance. However, it is possible that, under unique situations, governor control can establish a new equilibrium in an islanded group.

BCTC does not generally allow islanding conditions to exist for prolonged periods. On rare occasions, a controlled, temporary, area-wide separation, such as islanding of the North Coast area may be required for certain operation and maintenance purposes.

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Those PGFs that could be used for area island operation will be required to be equipped with remote control operation capability from the BCTC Control Centre.

8.4 Normal and Emergency Operations

The PG shall provide a 24 hour contact for normal and emergency operations. Communications between the PG and BCTC will be specified in a joint operating order.

8.5 SCADA, Telecommunications and Control

BCTC may require telemetering equipment for readings such as MW, MVAR, MW.h, and kV. Some or all of this data may need to be supplied continuously or via periodic dial-up reporting to BCTC Control Centres. The specific requirements will depend on the size of the plant, location, strength of the transmission system at the Point of Interconnection, other generation in the area, and other factors. Telemetry information guidelines are as shown in Table 8, Table 9 and Table 10 below:

Table 8: Telemetry Data Requirements for Generators up to 10 MVA

Data Telecommunications (1)

Plant level: MW, MVAR, MW.h (hourly), kV, interconnection status. Line telemetry at POI (if different than plant): MW, MVAR, kV.

Unsolicited report by exception via dial-up IED/RTU (2) with DNP 3.0 protocol; 2-minute maximum to establish connection for BCTC interrogation on demand; Reports to a BCTC Control Centre. Datalinks between control centres. E.g., between the PG and BCTC Control Centres. Non-dedicated Telephone analog business line, with entrance protection (3), provided overall polling interval for all data is less than or equal to 4 seconds, or Stationary Satellite Broadband Link, provided overall polling interval for all data is less than or equal to 4 seconds.

Notes:

1) The new generator project is required to install equipment to satisfy these BCTC telemetry requirements; requirements may be increased by Real Time Operations if deemed to have safety or significant operational impacts.

2) IEDs (Intelligent Electronic Devices) may be an RTU (Remote Terminal Unit), digital meter or digital relay.

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3) The IED shall be capable of providing all required data to BCTC Control Centre at a one second polling frequency.

Table 9: Telemetry Data Requirements for Generators between 10 and 30 MVA

Data Telecommunications (1)

Unit level: MW, MVAR, kV, MW.h (hourly), connection status, running status; PSS status if equipped with PSS; AVR status if equipped with AVR. Line telemetry at POI (if different from unit aggregate): kV, MW, MVAR

Real-time report by exception using an IED/RTU (2) with DNP 3.0 protocol reporting to a BCTC Control Centre. Datalinks between PG and BCTC Control Centres Single dedicated (always on) telecommunications link, i.e. Telus lease, PLC, fibre optic, microwave, etc., provided overall polling interval for all data is less than or equal to 2 seconds, or Stationary Satellite Broadband Link, provided overall polling interval for all data is less than or equal to 4 seconds.

Notes:

1) The new generator project is required to install equipment to satisfy these BCTC telemetry requirements; requirements may be increased by Real Time Operations if deemed to have safety or significant operational impacts.

2) IEDs (Intelligent Electronic Devices) may be an RTU (Remote Terminal Unit), digital meter or digital relay.

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Table 10: Telemetry Data Requirements for Generators 30 MVA and Above

Data Telecommunications (1)

Unit level: MW, MVAR, kV, MW.h (hourly), connection status, running status, PSS status if equipped with PSS, AVR status if equipped with AVR, tap changer position (if equipped with on-load automatic tap changer), low side kV (if equipped with on-load manual tap changer). Line telemetry at POI (if different from unit aggregate): MW, MVAR, kV.

Real-time report by exception using an IED/RTU (2) with DNP 3.0 protocol reporting to nearest BCTC facility for routing of data to both BCTC Control Centres. Dedicated (always on) telecommunications link, i.e. Telus lease, PLC, fibre optic, microwave, etc., provided overall polling interval for all data is less than or equal to 2 seconds.

Notes:

1) The new generator project is required to install equipment to satisfy these BCTC telemetry requirements; requirements may be increased by Real Time Operations if deemed to have safety or significant operational impacts.

2) IEDs (Intelligent Electronic Devices) may be an RTU (Remote Terminal Unit), digital meter or digital relay.

8.6 Other Requirements

Other operating and technical requirements will be determined by interconnection studies and in negotiations or consultations between the PG and BCTC when the need arises.

9. Commissioning Requirements

9.1 General

The PG has full responsibility for the inspection, testing, and calibration of its equipment, up to the Point of Interconnection, consistent with the Standard Generator Interconnection Agreement.

9.1.1 General Commissioning Requirements:

BCTC requires the following for the commissioning of the PG’s equipment:

Performance of all commissioning by competent personnel,

Compliance with the various levels of Declarations of Compatibility and Commission Notice to Energize, as required, defined in Appendix E – Declaration of Compatibility prior to loading, synchronizing and operating. These requirements refer to key aspects where BCTC must be confident of the correct operation, settings, calibration and/or installation of equipment. This may include, but not limited to, generator

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performance, protective relaying, telecommunications, and revenue metering. Inspection and testing shall confirm the compatibility of the PG’s equipment and controls with BCTC System where applicable,

Testing to confirm the safe, reliable and effective operation of all equipment in the PGF under normal and abnormal conditions,

Assignment of a BCTC Field Coordinator to the installation in order to assure compatibility by:

Witnessing any part of the commissioning tests,

Requesting additional testing, or

Conducting BCTC’s own testing.

Correction of any deficiencies identified during commissioning before the interconnection is approved for operation, and

Submission of a copy of the commissioning reports signed and sealed by a Professional Engineer.

9.2 Generator Commissioning Requirements

BCTC requires the following for the commissioning the PGF or after modifications to the PGF at the PG’s costs:

Testing to confirm generator model data as per WECC’s policy “GENERATING UNIT MODEL VALIDATION POLICY”, which can be accessed from their web site (http://www.wecc.biz/), such that test data be made available within:

180 days of a generator entering Commercial Operation, and

180 days of changes made to an in service generator, which modified equipment, control settings, or software that influences the behaviour of the plant with respect to the Transmission System (e.g. excitation retrofit, additional control function within a controller, turbine modification, voltage regulator and Power System Stabilizer tuning modification, etc.); only those portions of the generating unit model that can be influenced by the modifications need to be tested and validated. (See Appendix D – Data Requirements for more details.)

Provision of results of the generating unit testing and model validation to BCTC for review and content approval before connecting the PG’s generating unit(s) to the Transmission System for any purpose other than commissioning and testing, and

Re-testing of some or all generating units and their models validated periodically at least every five years as may be required by WECC or as required by other reliability authorities having jurisdiction in BC.

9.3 Protection Equipment

Commissioning of protection equipment shall include but not limited to:

Ratio, phase and polarity testing of current transformers and potential transformers,

Calibration checks of each protective relay by injecting the appropriate AC quantities,

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Functional testing of the protective relays to circuit breakers and telecommunications equipment. Testing shall include minimum operating point verification for relays,

Functional and timing testing of Remedial Action Scheme facilities, such as generation shedding facilities, and

Load tests of protective relays immediately after initial energization.

The settings applied to selected relays shall be as determined and/or reviewed by BCTC.

9.4 Telecommunications Equipment

Functional end-to-end testing of telemetry, protection, alarms, voice, and related equipment shall be performed.

9.5 Operating, Measurement and Control Systems Commissioning Requirements

BCTC requires the following testing of the control and measurement systems:

Testing to prove the proper operation of synchronization controls, governors, excitation systems, voltage regulators, Power System Stabilizer systems and other control schemes,

Testing to confirm the ratio, phase and polarity of non-protection instrument transformers,

Testing of the revenue metering in accordance with Measurement Canada requirements, and

BCTC may require a representative to witness the commissioning of the Power Parameter Information System (PPIS). Commissioning includes downloading and testing the device configuration, checking instrument transformer connections, testing UPS function, and confirming dial-up connection and downloading of data.

9.6 Apparatus Commissioning Requirements

Commissioning of station apparatus equipment shall be performed in accordance with the Canadian Electrical Association's "Commissioning Guide for Electric Apparatus" or equivalent. Commissioning shall include but not limited to:

Power factor tests of high voltage equipment at 10 kV to ensure insulation adequacy,

Timing and resistance tests of main and/or generator circuit breaker(s),

Integrity checks of auxiliary switches, and

Continuity checks on control, power and protection cabling to equipment.

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10. Maintenance Requirements

10.1 General

The PG has full responsibility for the maintenance of its equipment, up to the Point of Interconnection, consistent with the Standard Generator Interconnection Agreement. General maintenance requirements include:

Maintenance work shall be done by competent personnel; and

The PG shall maintain equipment used to control, generate, protect, and transmit electricity to the Transmission System, and perform vegetation management all in accordance with applicable reliability standards to ensure that the reliability of the Transmission System is not adversely affected.

BCTC reserves the right to inspect and test the equipment given reasonable notice.

10.2 Scheduled Outages Requirements

PG shall coordinate planned outages for maintenance on PG’s equipment with the BCTC Control Centre. Planned outages should not impair the safe and reliable operation of the Transmission System.

10.3 Preventive Maintenance Requirements

The PG shall have a preventive maintenance program and retain maintenance records for audit purposes in compliance with applicable standards imposed by NERC/WECC or a reliability organization having jurisdiction in BC. Maintenance will be based on time or on other factors, including performance levels or reliability, and shall follow the manufacturers' recommendations and/or accepted electric utility preventive maintenance practices.

10.4 Protection and Telecommunications Equipment

Periodic maintenance of protection equipment shall include, but not limited to, the calibration and functional testing of all protective relays, the associated telecommunications equipment, and the trip testing of the corresponding circuit breakers.

The interval between tests for protective relays and telecommunications equipment shall be in accordance with applicable WECC requirements and Industry Canada regulations.

Facilities shall be available for testing to provide isolation from current transformers, potential transformers and trip buses and to allow AC injection tests.

11. Regulatory and Reliability Requirements

BCTC’s and the PG’s obligations shall be subject to any required approval or certificate from one or more governmental authorities. The BCUC has regulatory oversight of BCTC and all agreements between BCTC and the PG.

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BCTC and the PG shall comply with the applicable NERC standards, WECC standards, and reliability standards approved by regulatory organizations having jurisdiction in BC as well as respective NERC Operating Policies, WECC Minimum Operating Reliability Criteria (MORC), and any other WECC guides or policies that apply.

12. References

The following list of standards is provided for reference only. It is the responsibility of the PGs to comply with all applicable standards.

12.1 BCTC

BCTC Transmission Line Construction Requirements

12.2 CSA

CSA C22.1, C22.2 and C22.3 – Canadian Electric Code Parts I, II & III.

CSA C57-98 (Reaffirmed 2002) Electric Power Connectors for use in Overhead Line Conductors

CSA C83-96(Reaffirmed 2000) Communication and Powerline Hardware

CAN/CSA-C411.1-M89 (reaffirmed 2004) AC Suspension Insulators

CAN/CSA-C411.4-98 (Reaffirmed 2003) Composite Suspension Insulators for Transmission Applications

CAN/CSA-G12-92 (Reaffirmed 2002) Zinc-coated Steel Wire Strand

CAN3-C108.3.1-M84 Limits and Measurement Methods of Electromagnetic Noise from AC Power Systems, 0.15 – 30MHz

12.3 IEEE Standards (www.ieee.org)

IEEE Std C37.1 – Standard Definition, Specification and Analysis of Systems Used for Supervisory Control, Data Acquisition and Automatic Control

IEEE Std C37.2 – Standard Electrical Power System Device Function Numbers

IEEE Std C37.122 – Standard Gas Insulated Substations

IEEE Std. C50.12 – Salient Pole Synchronous Generators

IEEE Std. C50.13 – Cylindrical-Rotor Synchronous Generators

IEEE Std C57.116 – Guide for Transformers Directly Connected to Generators

IEEE Std C62.92.5 – Guide for the Application of Neutral Grounding in Electrical Utility Systems

IEEE Std 80 – Guide for Safety in AC Substation Grounding

IEEE Std 81 – Guide for Measuring Earth Resistivity, Ground Impedance, and Earth Surface Potentials of a Ground System

IEEE Standard C95.6 – 2002 IEEE Standard for Safety Levels with respect to Human Exposure to Electromagnetic Fields 0 to 3 kHz

47 OCTOBER 10, 2008

IEEE Std 100 – The New IEEE Standard Dictionary of Electrical and Electronics Terms (ANSI)

IEEE Std 122 – Recommended Practice for Functional and Performance Characteristics of Control Systems for Steam Turbine-Generator Units

IEEE Std 125 – Recommended Practice for Preparation of Equipment Specifications for Speed Governing of Hydraulic Turbines Intended to Drive Electric Generators

IEEE Std 421-1 – Standard Definitions for Excitation Systems for Synchronous Machines

IEEE Std 421-2 – Guide for the Identification, Testing and Evaluation of the Dynamic Performance of Excitation Control Systems

IEEE Std 421-4 – Guide for the Preparation of Excitation System Specifications

IEEE Std 519 – Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems

IEEE Std 525 – Guide for the Design and Installation of Cable Systems in Substations

IEEE Std 605 – Guide for Design of Substation Rigid-Bus Structures

IEEE Std 979 – Guide for Substation Fire Protection

IEEE Std 1127 – Guide for the Design, Construction and Operation of Electric Power Substations for Community Acceptance and Environmental Compatibility

12.4 WECC Guidelines (WECC website)

WECC Coordinated Off-Nominal Frequency Load Shedding and Restoration Plan

WECC Under-voltage Load Shedding Guidelines

WECC Generator Test Guide

WECC RMS Agreement to be entered into between the WECC and non-FERC-jurisdictional Transmission Operators within the WECC – Canadian Version

WECC Reliability Criteria

12.5 Others

ANSI C84.1 – Voltage Ratings for Electric Power Systems and Equipment (60 Hz)

Note: Ferrous material shall meet Energy Absorption Level 1 per Clause 6.2.4.1

O15-05 Wood Utility Poles and reinforcing Stubs

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Appendix A – Wind Generation Interconnection Requirements

Wind Generation Interconnection Requirements

A Supplement to

The 60 kV to 500 kV Technical Interconnection Requirements for Power Generators

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TECHNICAL INTERCONNECTION REQUIREMENTS FOR POWER GENERATOR

APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

A1. Background

This Appendix A specifies additional requirements for Wind Generating Facility (WGF). It is the responsibility of the PGs and their engineers to understand and comply with requirements in this TIR including this Appendix A when they are connecting their WGF. Only WGFs are subject to the requirements set forth in this Appendix A. Any requirements not specified in this Appendix A, shall conform to the general requirements set forth else where in the TIR. Any apparent inconsistency between the sections must be reported to BCTC by the PG or their representative for immediate resolution.

Wind Turbine Generator (WTG) technologies and their behaviour are significantly different from conventional hydro generators or fossil fuel generators. This Appendix A specifically describes the minimum additional requirements for interconnection of a WGF to the BCTC System.

The minimum technical requirements specified here do not recommend any preference in the type WTG technology or equipment to be used.

A2. Voltage Ride-through Requirements

In addition to Voltage and Frequency Operation during Disturbance in section 5.4.5, and to ensure the security of the Transmission System, WGFs are required to stay online during and after system faults if the voltage at high side of WGF step-up transformer(s) connected to the system, which is the point of measurement as shown in Figure A - 1, is within the defined boundaries and shall meet the following requirements:

1. Generators shall remain in-service if the voltage, measured at high voltage terminals of the WGF step-up transformer(s), is within the boundaries shown in Figure A - 2:

a. During system faults (either multi-phase faults with normal clearing or single line to ground faults with delayed clearing), and

b. Immediately after the fault is cleared unless clearing the fault effectively disconnects the generator from the interconnected system.

This requirement does not apply to faults that occur between the generator terminals and the high side of the WGF step-up transformer(s).

2. In the post transient period, generators shall remain in-service during low voltage excursions as specified in WECC Table W-15.

3. Following a disturbance, WGF shall return to the pre-disturbance power output, assuming voltage and frequency are within the normal operating range. The reactive power output shall also respond in a controlled fashion to support the system voltage recovery.

5 NERC/WECC Planning Standards”, Western Electricity Coordinating Council, revised April 10, 2003: Available at: http://www.wecc.biz/documents/library/procedures/planning/WECC-NERC_Planning%20Standards_4-10-03.pdf.

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APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

Figure A - 1: Typical Wind Generating Facility Configuration associated with Points of Measurement for Voltage Ride-through and Reactive Power Requirement.

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APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

Figure A - 2: Voltage Ride-through Requirement6

Voltage Ride-through Requirement [3]

Seconds

6 “The Technical Basis for the New WECC Voltage Ride-through (VRT) Standard”, A White Paper Developed by the Wind Generation Task Force (WGTF), June 13, 2007: Available at: http://wecc.biz/documents/library/TSS/Voltage%20Ride-through%20White%20Paper_6-13-07.pdf

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APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

A3. Reactive Power and Voltage regulation

A3.1 Reactive Power Requirements

WGF is required to have a capability providing a range of 0.95 leading to 0.95 lagging power factor as measured at the Point of Interconnection when generating at rated name plate capacity. An adequate amount of reactive power capability shall be available over the full range of operating conditions for various generation levels to ensure acceptable transient, dynamic and steady state voltage performance requirement. This level of capability should be determined based on the operational needs of the WGF.

WGF shall use the appropriate ratio of discrete (mechanically switched shunt capacitors) and dynamic reactive devices (such as rotating machine VAR capability, or equivalent dynamic reactive devices like SVC or STATCOM.), to meet steady-state and transient stability performance requirements based on NERC/WECC planning standards during and after a disturbance. The Interconnection Impact Study will specify the ratio on a site by site basis based on the system considerations. The dynamic VAR requirement will be finalized based on the final WGF plant design and operation requirements.

A3.1.1 Voltage Operating Limits

Generators within a WGF shall meet the requirements of section 5.4.5.

Note: The Voltage Ride-through (VRT) requirements in section A2 of this Appendix shall override the requirements indicated in Table 7, section 5.4.5.

A3.1.2 Power System Stabilizers and Automatic Voltage Regulation

WTG may not be required to have power system stabilizers.

Automatic voltage regulation is required to automatically regulate the voltage at the POI. The intent of WGF voltage regulation is to be reasonably comparable to synchronous generators to ensure coordinated control behaviour between all types of generating facilities.

Joint VAR control may be required for the WGFs that are closely connected electrically.

For connecting to a strong part of the system, BCTC may allow a WGF with installed capacity of less than 10 MVA not to have an automatic voltage regulation system.

A4. Frequency control

A4.1 Frequency Operating Limits

WTG is required to meet the requirements of section 5.4.5.

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APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

A4.1.1 Frequency Regulation

WTG capable of an output power level greater than 10 MW may be required to have frequency regulation capability for use under certain islanded operating conditions. If it is required, this requirement will be specified in the Interconnection Impact Study for the proposed project.

A5. Protective Relaying

A5.1 General

WGF shall meet the protective requirements in section 6.

This section amends and clarifies these requirements as they pertain specifically to WGF.

A5.2 Telecommunication Requirements for Protective Relaying Purposes

In addition to the requirements described in section 6 , the following should be noted.

A5.2.1 Direct Transfer trip (Protection)

A single direct transfer trip is required to trip the WGF HV line terminal circuit breaker whenever the remote utility terminal(s) opens or if there has been a protection operation at that line terminal.

This ensures removal of the WGF from the network whenever there has been a transmission line fault. To keep costs to a minimum, a class 3, as defined by WECC, is acceptable.

A5.2.2 Communications Assisted Protection Tripping

If communications assisted line protection is required (refer to section A5.3 “Line Protection”), the technical requirements will be defined by BCTC.

Generally such facilities will be class 1 or class 2 as defined by WECC.

A5.3 Line Protection

Redundant (primary and standby) line relaying facilities shall be provided. For ease of testing and maintenance, duplicate systems are preferred.

A5.3.1 Communications Assisted Protection Tripping

For 230 kV and above system connections, high speed detection of faults for 100% of the transmission circuit shall be provided. Communications assisted relaying (for example, a permissive over/under reaching transfer trip scheme, POTT) for both the primary and standby system must be used. Relaying at the WGF terminal must be of the same type and operating principle as used at the utility line terminals.

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For transmission line voltages lower than 230 kV, a communications independent relaying scheme may be acceptable. Acceptability will be determined at the time when the WGF proposal is reviewed.

A5.3.2 Communications independent Relaying Scheme

The transfer trip facilities, described in section A5.2.1 will provide the primary system.

The standby system shall consist of the following facilities at the WGF:

For detection of ground faults:

Inverse time over-current ground protection with an instantaneous tripping element

For detection of multi-phase faults: Timed under-voltage protection connecting to HV Instrument Transformers on the

transmission system side of the WGF main transformer.

Applying carefully selected settings for this protection, paying particular attention to ensure that:

a. The protection shall not mis-operate, based on the WGF ride-through capability,

b. The protection coordinates with utility protection remote from the connected transmission line, and

c. The protection coordinates with the remote end line auto reclosing time.

A5.4 Quality Protection

Timed under-voltage, over-voltage, under-frequency and over-frequency protection shall be provided and shall:

Be set and coordinated with the ride-through capability of the WGF,

Meet WECC requirements, and

Meet specific BCTC requirements which will be described at the time when the WGF proposal is reviewed by BCTC.

A5.5 Under-frequency Protection

Under-frequency load shedding may be required for those instances when the WGF is a load.

Note: Under-frequency load shedding typically has very short time delays (cycles) whereas the under-frequency component of quality protection typically has a much larger time delay (seconds). Under-frequency load shedding settings will be specified by BCTC in accordance with WECC requirements. (Refer to section 5.4.5)

TECHNICAL INTERCONNECTION REQUIREMENTS FOR POWER GENERATOR

APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

A5.6 Disturbance Monitoring

A disturbance monitoring system shall be provided by the WGF and shall be able to:

Produce records in electronic form as per the latest COMTRADE standard. [Reference: C37.111-1999 IEEE Standard for Common Format for Transient Data Exchange (COMTRADE) for Power Systems.],

Monitor HV phase and residual line voltage (3Vo), HV phase and residual line current (3Io), line protection and entrance protection operations,

Time synchronization via a GPS clock to 1 ms accuracy, and

Triggering by line protection or entrance protection operation.

Note: the disturbance monitoring functions can be provided within the protective relay(s) provided as part of line protection and/or entrance protection.

Disturbance records shall be made available to BCTC within one week of the disturbance.

A5.7 Information Required from Wind Generating Facility Proponent

In addition to the information requirements described else where in the TIR, the WGF proponent shall provide:

1. Fault current decrement for a close-in as well as remote line end 3 phase faults,

2. Fault current decrement for a remote line end resistive ground fault (value of resistance determined at the time of review), and

3. Confirmation, by actual simulated tests of the WGF line protection, that the WGF HV circuit breaker will be tripped for the faults described in (1) and (2).

Note: if confirmation, satisfactory to BCTC, can be provided then the transfer trip facilities described in section A5.2.1 may be waived.

A6. Electric power quality

Power quality requirements for all generating facilities including WGF are described in section 6.4.

The WGF proponent must be aware that energization of the interconnection transformer from the grid will result in a temporary voltage dip. The maximum allowable instantaneous voltage dip on a worst single phase RMS basis is 6% once per eight hours. In some cases, with prior approval from BCTC, a voltage dip not exceeding 9% might be allowed.

The WGF proponent is responsible for performing studies where necessary to ensure that they avoid self-excitation and other low-order harmonic resonance phenomenon on their collector system due to shunt capacitors (or cable charging).

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APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

A7. System Requirements for Point-of-Interconnection Equipment

A7.1 Integration Switching Station

WGF interconnection equipment requirements are similar to other generation interconnection with the difference that they are often large relative to most PGFs and have a medium voltage (MV) collector network. Larger generation such a typical WGF shall have appropriate grid switching facilities in accordance with Good Utility Practice.

The underlying principle of connecting private networks to the grid is that the grid owner retains control of all switching for events that impact the grid. This means that faults on the independent network shall be cleared first by the independent PG protection with backup clearing by equipment owned and operated by the grid operator to clear the fault without causing an outage to grid lines. Similarly, faults on the grid supplied from an independent PG shall first be cleared by protection and circuit breakers owned and operated by the grid operator with time delayed backup by the independent PG protection. These needs require that independent PG shall always terminate either at an existing grid substation where appropriate switching will be supplied or at a dedicated grid station owned and controlled by the grid operator.

The following diagram illustrates the basic connection arrangement for connecting a WGF to the grid at a nearby transmission line.

Figure A - 3: Basic Connection Arrangement for Connecting a WGF

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APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

Comments on the Point of Interconnection requirement are as follows:

The WGF proponent will not have physical access to the grid station for operational purposes once the station is energized and so will require the necessary switching and isolation equipment on its side of the ownership boundary which will be delineated by a fence.

Station service power is required in the grid station. It may be necessary at remote sites to provide a dedicated step-down transformer from the HV bus as the primary supply but normally the service power supply can be obtained from the WGF station or from local distribution.

A7.2 System Grounding

The transmission system shall be effectively grounded to keep transient voltages within the over-voltage withstand capability of system equipment.

This requires that all generation sources feeding into the grid via transformers are effectively grounded on the HV side.

A7.3 Grid Connection Transformer

The general equipment requirements for insulation and fault withstand are as for any other grid connection and are covered else where in the TIR.

A HV YG – LV delta is required so that the step-up transformer is an effective source of zero sequence current on the HV side so as to ensure that effective grounding of the HV grid is maintained. It is also required to separate the HV grid zero sequence from the MV grid zero sequence for protective relay ground coordination purposes.

Typically WGF will have a medium voltage (MV) collector network and need a ground source on the MV side of the step-up transformer. The recommended HV grounded wye-LV delta transformer does not provide the desired MV ground so a grounding transformer is recommended on the MV side in conjunction with a HV YG-LV delta transformer.

A8. Transmission System Operation

The WGF proponent is responsible for the validity of information (data, models and associated settings) that it or its supplier submits to BCTC so the latter can conduct the real-time operational studies required to assess the impact of operating the WGF to the transmission system.

A8.1 Data Requirements

BCTC requires real-time data from each generating plant for effective operation of the BCTC System. This data must be provided in a form compatible with transmission provider equipment. The real-time data required for all types of generating plants depends on their

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APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

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capacity and is specified in the Table 8, Table 9, and Table 10 in section 8.5. The following are additional requirements for WGF:

The Intelligent Electronic Device (IED) must be capable of providing all required data at a one second polling frequency and must be capable of supporting unsolicited reporting.

Data requirements at the collector bus for each of the WGF feeders7 in addition to what is listed in Table 8, Table 9, and Table 10 in section 8.5:

MW (same time resolution as in Table 8, Table 9, and Table 10);

MVAR (same time resolution as in Table 8, Table 9, and Table 10);

MW.h (hourly);

Average wind speed (every 10 seconds, if required, for the wind turbine generators connected to the feeder); and

Average wind direction (every 10 seconds, if required, for the wind turbine generators connected to the feeder).

The following additional information from each meteorological tower at multiple elevations (to be determined between the WGF owner and BCTC) for wind generating sites shall be made available through telemetry to the System Operator:

Wind speed (every 10 seconds);

Wind direction (every 10 seconds); and

Relative humidity (every 30 min).

Status of circuit breakers for transformers and all shunt compensation devices located at the WGF substation.

The tap position of the substation transformer at the WGF, if fitted with on-load tap-changers.

For collector systems in WGF with more than one feeder and individual switching devices: feeder status, feeder kV, feeder MW, feeder MVAR and feeder MW.h. Each feeder may be represented and modeled as a single generator.

The additional data noted above shall be transmitted to the System Operator in the same SCADA data channel as the data noted in Table 8, Table 9, and Table 10. This will usually result in a higher bandwidth SCADA channel than for non-wind PGs.

A8.2 Dispatchability and Curtailability

BCTC will curtail a generator for reliability reasons in the BCTC System. The WGF shall be able to complete the curtailment amount within 10 minutes of notification to the generator owner/operator at any time (7x24). Otherwise, there may be requirement to implement

7 A feeder consists of several wind turbine generators in a wind generation facility that is electrically connected in parallel on a collector bus which is then connected through a step-up transformer to the Point of Interconnection. A wind generating facility may have one of more feeders in its configuration.

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APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

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automatic curtailment in accordance with instruction or control signal from the BCTC System Operator.

A8.3 Special Communications Requirements for Wind Generating Facilities

BCTC shall be notified by the WGF owner/operator within 10 minutes of an event resulting in a reduction in the WGF capacity of greater than 75 MVA for any reasons including high wind.

A8.4 Planned Outage Coordination

See BCTC System Operating Order 1T-22 for detailed procedures. This System Operating Order is available at http://www.bctc.com/transmission_system/system_operating_orders/.

A8.5 Ramp Up/Down Limitation

The real power output of the WGF is required to be adjustable during start-up. The normal maximum ramp up rate shall be the lesser of, (a) 10% of the aggregated MW capacity of the WGF in MW per minute, or (b) 80 MW per minute. On a case by case basis, BCTC may specify a maximum WGF power ramp down rate if there is any adverse impact to the control performance or reliability of the BCTC System.

A9. Responsibility for Technical Information to be Submitted to BCTC

The WGF proponent is responsible for the validity of information (data, models and associated settings) that it or its supplier submits to BCTC so the latter can conduct the studies required to assess the impact of connecting the WGF to the Transmission System.

WGF system models including load-flow, transient and dynamic models, as required by BCTC, shall be submitted to BCTC in a timely manner for Interconnection Studies.

A9.1 Information Required for Dynamic Modelling

The WGF proponent is responsible for providing in a timely manner a detailed simulation model of the WGF in Siemens PTI’s PSS/E format to BCTC for Interconnection Impact Studies.

After commissioning tests of the WGF are completed, the final models and parameters in Siemens PTI’s PSSE format and also in GE PSLF format shall be provided to BCTC.

The WGF proponent shall provide compliance tests demonstrating that the provided model behaves like the installed WTG. If the WTG behaviour does not conform to the model, the WGF proponent is responsible for any additional costs for interconnection to the Transmission System.

The WGF proponent must provide BCTC permission to share all WGF modeling data with reliability organizations such as WECC, NWPP, and NERC, and with members of those entities who have permission to access that information.

TECHNICAL INTERCONNECTION REQUIREMENTS FOR POWER GENERATOR

APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

A10. EMTP Modeling Information

A proven EMTP (electromagnetic transients program), specifically PSCAD/EMTDC, model of each proposed WTG type, the collector network, and any static or dynamic VAR compensating components (i.e., Statcoms, SVCs, D-VARs) shall be provided to BCTC for Interconnection Impact Studies. The dynamic components of the WGF shall be modelled such that is representative of the full dynamic response capability of that component (i.e., the component model shall provide the correct dynamic range and output as intended by the manufacturer’s design). Failure to supply a PSCAD model will force BCTC to take a more conservative approach to the design and may result in a significant additional cost to the WGF proponent. More detailed requirements of the model are provided in Appendix 1 below.

The model can optionally connect at the high voltage level (for example, 230kV) or at the mid-voltage level (for example, 35kV). If the model is black-boxed at the high voltage level, then inputs for transformer impedances, ratings, winding configuration, rated voltages, and tap settings should be available.

The model shall be available to study engineer designated by BCTC, whether this is the utility, consultant, or manufacturer (with the understanding that a Non-Disclosure Agreement may be required). The model is not intended to be made public.

A11. Other Considerations

BCTC may require that:

Some or all of the generators in the WGF may be required to be tripped after a contingency by a special protection system such as a generation shedding RAS,

Any WGF greater than 10 MW be equipped with a control system to receive control signals for such functions as limiting maximum real power, and

A control system be added to gradually shut down the wind generators.

A11.1 Black Start Capability

BCTC does not require that the WGF have black start capability. However, it is up to the WGF proponent to decide, in consultation with their engineer, whether black start is a necessity for the WGF to self-start and energize the WGF while the WGF is isolated from BCTC System at the Point of Interconnection.

A11.2 Back-up Power

Back-up power is deemed to be the supply of power from the transmission system to energize the WGF thus allowing the WGF to recover from a total shut-down. It is up to the WGF proponent, and their engineer, to make arrangements for back-up power supply with an electric power service provider.

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APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

A11.3 Black Start Disconnection

A means shall be provided by the WGF proponent to facilitate the disconnection of the WGF by BCTC and to also prevent reconnection in the event of black start. It shall be possible for BCTC to send a trip and inhibit signal to the circuit breaker(s) at the WGF Point of Interconnection. A WGF may only be reconnected (i.e., made live) when the network is fully restored following instructions to reconnect from BCTC. If BCTC deems it acceptable to do so on rare occasions, the WGF may be instructed to reconnect prior to full grid restoration to assist with such purpose.

A12. Commissioning

See BCTC System Operating Order 1T-35, section 2 for details. This System Operating Order is available at http://www.bctc.com/transmission_system/system_operating_orders/.

A12.1 Special Factory and Commissioning Tests for Wind Turbine Generators

The following tests are required for the applicable type of Wind Turbine Generators:

The voltage ride-through capability for each type of turbine control;

Voltage regulation and reactive power response by demonstrating the ability to control POI voltage within full reactive power capability;

Reactive power control and the ability to provide continuous reactive power;

Availability of continuous reactive power over the range of voltage and frequency;

That measured harmonics are within acceptable levels;

That measured voltage flicker is within acceptable levels;

The coordination between WGF protection equipment and the transmission system. This may be done by simulation;

Power ramping and power curtailment ;

Availability of SCADA and meteorological data specific to WGF; and

Any other tests required by BCTC.

If the Wind Turbine Generator behaviour does not conform to the model, the WGF proponent is responsible for any additional costs for interconnection to the Transmission System.

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APPENDIX A – WIND GENERATION INTERCONNECTION REQUIREMENTS

APPENDIX 1

INFORMATION REQUIRED FOR MODELLING IN PSCAD/EMTDC PROGRAM

A PSCAD model of the proposed Wind Turbine Generator must be provided to BCTC for Interconnection Impact Studies. The requirements of the model are:

Essential Requirements:

Detailed modelling of the main components, the controls, automatic voltage regulations, and protections must be included.

Blade/pitch controller is to be included.

The ride-through capability is to be modelled.

The model is to be capable of correctly reproducing the short circuit fault current contribution.

The model must be suitable for modeling open circuit, short circuit, balanced and unbalanced faults in the grid, including steady state & dynamic simulations.

The model should be available in the latest version of PSCAD and should support Compaq Fortran 90 V6.6.

The model must be capable of representing a single unit and should be adaptable to represent any reasonable number of identical units with a minimum of effort.

It must be possible to run a simulation with a case containing more than one PSCAD model, where, for example, one model might represent a cluster of wind turbine generators connected to one branch of a WGF.

The model should support the “snapshot” feature in PSCAD to allow the simulation to be saved and restarted at any point in time.

The model must come with documentation to explain the assumptions and basic operation of what is being modelled as well as a user manual.

Model validation documents comparing the PSCAD model response to real system measurements must be provided.

The control of internal and external shunt capacitor banks, as required by the overall controller, is to be included.

A correctly functioning PSCAD case including the WGF model connected to a simple AC system must be provided.

Non-essential Requirements:

Switching-based model (for doubly fed, SVC and converter based models) for harmonic/power quality studies must be provided.

Blade dynamics (i.e. inertia of blades, gearbox, etc.) should be modelled for torsional interaction/dynamic studies.

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“Blackbox” models are acceptable, provided the following inputs/outputs are available:

Inputs (minimum):

Scaling factor to represent N lumped machines

Power input (pu) Control mode (local voltage control, reactive power control, and external control)

Any additional external settings which may need to be modified (i.e. voltage control gains, etc.)

Compounding impedance (pu) for voltage controller Protection settings which may need to be modified (i.e. ride-through, under-voltage, r

over-voltage, under-frequency, over-frequency, etc.); External control input of the high side breaker (if the high side breaker is included in

the blackbox model) Wind gust input

Others (model #, presence of optional control/hardware operational features)

Outputs (minimum):

Trip indication (also indicates which protection operated) Measured RMS voltage (pu), real and reactive output power

In addition to the requirement that a PSCAD model of the wind turbine generator be provided, the following additional information should be provided:

Harmonic and flicker data

Graphs of reactive power versus voltage

Protection diagrams and settings

TECHNICAL INTERCONNECTION REQUIREMENTS FOR POWER GENERATOR

APPENDIX B – PROTECTION EXAMPLE INSTALLATIONS

Appendix B – Protection Example Installations

Figure B - 1: PG Line Protection Utilizing Multi-function Distance Relays*

POI

New PG FacilityBCTC Facility

21LS

21L

*

*

Entrance Protection

Figure B - 2: PG Line Protection Utilizing Line Current Differential Protection

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APPENDIX C - POWER PARAMETER INFORMATION SYSTEM

Appendix C – Power Parameter Information System

C1. General Description

The Power Parameter Information System (PPIS) monitors and records individual power-line electrical parameters (KW, kVAR, kV, kVA, PF, Hz, Harmonics, Transients, Min, Max, Events and etc.) The PPIS is usually installed at the PGF but another suitable location may be selected with agreement between the PG and BCTC. Supplied and installed by PG including hardware and software program. The on-line PPIS checks the power system performance and provides technical information on electrical system operations in steady and dynamic states, and during power outages. This information shall be made available to both the PG and BCTC technical personnel.

C2. Power Parameter Information System Requirements

The PPIS consists of a multi-profile power meter with local display unit; protection grade voltage transformers (VT, 120V secondary) and current transformers (CT, 5A secondary); FT-1 type test blocks or alternatively, revenue type blocks; analogue business telephone line with facility entrance protection; telephone modem (set at 9600 Baud); RS232 modem cable; and an un-interruptible power supply (UPS). These components are interconnected to provide power parameter information via either the local display unit or remote access with application software acceptable to BCTC.

The full three-phase VTs and CTs (including optional transformer neutral CT where required) installed at the PGF are the input source to the power meter. The VT and CT test blocks are for testing and maintenance purposes, while the telephone modem provides remote access, and the UPS ensures minimum of 4 hours of PPIS operation during power outage. The PPIS system is preferably installed indoors in the control cubicle with front mounted local display unit, but may be located in an individual cabinet beside the revenue metering cabinet if necessary.

C3. Commissioning

The PPIS system shall be commissioned by the PG prior to generator operation. It shall be checked, tested and recorded for correct wiring, phasing, voltage and current levels as well as functional tests for local and remote access by BCTC. The PPIS configuration, programming, settings and recordings tasks are to be done by BCTC technical personnel.

C4. Operation and Maintenance

BCTC will connect to PPIS on-line and/or periodic download the captured information. This system requires very low maintenance. However, BCTC requires access to the system on site for inspection, testing and calibration purposes.

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APPENDIX C - POWER PARAMETER INFORMATION SYSTEM Figure C - 1: PPIS Reference Drawing 1

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APPENDIX C - POWER PARAMETER INFORMATION SYSTEM Figure C - 2: PPIS Reference Drawing 2

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APPENDIX D – DATA REQUIREMENTS

Appendix D – Data Requirements

The following outlines data that will be required at various stages of: planning, design, commissioning and in-service of the PGF. This data is required by BCTC to ensure suitable steps are taken to interconnect the PGF to the Transmission System.

D1 Submission Requirements

D1.1 Format

Wherever possible, all documents shall be provided in both paper and electronic forms.

The preferred format for reports and other documents is Word for Microsoft Office; for data, drawing indexes and the like is Excel for Microsoft Office.

The preferred formats for drawings are (in order of preference): (i) Auto-CADD *.DXF format, (ii) Intergraph MicroStation*.DGN format, and (iii) Portable Document Format (PDF).

Unless legibility is a problem, all drawings shall be submitted on either, ‘A’-size (8.5” x 11”; 21.6cm x 27.9cm), or 'B'-size, sheets (11” x 17”; 27.9 cm x 43.2 cm).

All data shall be submitted using the Generator Interconnection Equipment Statement (GIES), which is located on the BCTC website. The PG shall provide one paper copy, signed and sealed by a Professional Engineer registered in the Province of British Columbia, along with an electronic copy in Excel format.

All drawings, maps, data curves or other material requested within the GIES shall be provided as both paper and electronic copy.

D1.2 Typical Information and Data for PG Interconnection Studies

D1.2.1 Connection Location

Location information required will vary depending upon the proposal.

Locations of new substations, generators or new taps on existing lines shall include county, township, range, elevation, latitude and longitude. BCTC also requires driving directions to the location for a site evaluation. The information shall:

Identify the substation if connecting to an existing BCTC substation,

If the connection is between two existing substations, identify both substations,

For connection to an existing BCTC transmission line, identify the line by name as well as the location of the proposed interconnection, and

If the request includes a new substation or generator site, identify the proposed location.

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APPENDIX D – DATA REQUIREMENTS

D.1.2.2 Electrical Data

The electrical data required will depend upon the type of connection requested.

1. Electrical One-Line Diagram

The electrical one-line diagram should include equipment ratings, equipment connections, transformer configuration, generator configuration and grounding, bus, circuit breaker and disconnect switch arrangements, etc.

2. Generator Data

If different types of generators are included, data for each different type of generator and generator step up transformer shall be provided in addition to the following data:

2.1 Generator General Specifications Energy source (e.g., natural gas, coal, wind, hydro, co-generation, geothermal, etc.)

Number of rotating generators

Number of turbines, combustion, steam, wind, hydro, etc.

Total project output, MW (@ 0.90 PF for synchronous generators)

Station service for plant auxiliaries, KW, kVAR

Station service connection plan

2.2 Generator Data, Synchronous Machines

Data for each different rotating-machine generator assembly generator, turbine, and shaft shall be provided. Also, PG shall provide the graphs and parameters for each type and size of specified generator as supporting technical documentation identifying the following information:

Reactive capability, ‘P-Q’ curves

Excitation ‘Vee’ curves

Saturation and synchronous impedance curves

Identifier (e.g., GTG #12)

Number of similar generators

Complex power, kVA

Active power, KW

Terminal voltage, kV

Machine parameters

a. Sb – Complex power base (MVA) upon which machine data is specified b. H – Normalized rotational kinetic energy of the generator/turbine/shaft assembly, KW-sec/kVA c. WR2 – Moment of inertia, lb. Ft2 d. Ra – Armature resistance, pu

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e. Xd – Direct axis unsaturated synchronous reactance, pu f. X’d – Direct axis unsaturated transient reactance, pu g. X’q – Quadrature axis saturated and unsaturated transient reactance, pu h. X”d – Direct axis saturated and unsaturated sub-transient reactance, pu i. XI – Stator leakage reactance, pu j. X2 – Negative-sequence reactance, pu k. X0 – Zero-sequence reactance, pu l. Xn – Zero-sequence unit grounding reactance, pu m. Rn – Zero-sequence unit grounding resistance, pu n. T’do – Direct axis transient open circuit time constant, seconds o. T’qo – Quadrature axis transient open circuit time constant, seconds p. T”do – Direct axis sub-transient open circuit time constant, seconds q. T”qo – Quadrature axis sub-transient open circuit time constant, seconds r. S(1.0) – Saturation factor at rated terminal voltage, A/A r S(1.2) – Saturation factor at 1.2 per unit of rated terminal voltage, A/A

Excitation system modeling information

a. Type (static, ac rotating, etc.) b. Maximum/Minimum DC current c. Maximum/Minimum DC voltage d. Nameplate information e. Block diagram f. Power System Stabilizer (PSS) type and characteristics

Speed governor information with detailed modeling information for each type of turbine.

a. Turbine type (Combustion, Steam, Wind, Hydro) b. Total capability, MW (available peak operation rating) c. Number of stages d. Manufacturer and model, if known e. Frequency vs. time operational limits, seconds at Hz f. Maximum turbine ramping rates, MW/minute, ramp up and ramp down

2.3 Generator Data, Asynchronous Machines Shunt reactive devices (capacitor banks) for power factor correction with induction

generators or converters.

a. PF without compensation b. PF with full compensation c. Reactive power of total internal shunt compensation voltage, kVAR

AC/DC Converter devices employed with certain types of induction motor installations or with DC sources.

a. Number of converters b. Nominal AC voltage, kV

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c. Capability to supply or absorb reactive power, kVAR d. Converter manufacturer, model name, number, version e. Rated/Limitation on fault current contribution, kA

Machine parameters

a. Sb – Complex power base (MVA) upon which machine data is specified b. H – Normalized rotational kinetic energy of the generator/turbine/shaft assembly, seconds c. Rated terminal voltage, kV line-to-line d. Rated armature current kA e. Power factor at rated load f. Efficiency at rated load g. Slip at full load h. Starting current at rated voltage i. Starting torque at full voltage divided by full load torque j. Maximum torque divided by full load torque k. Number of poles l. Polar moment of inertia (lb-ft2), alternatively, the time to reach rated speed when full load torque is applied, seconds.

External Shunt Compensation

a. Bus Voltage b. Number and rating of each shunt capacitor section c. Voltage/PF controller scheme description and time delays

3. Transformer Data

The following data shall be provided for each unique transformer:

Transformer number or identifier

Number of similar transformers

Transformer type and number of windings, (e.g. Autotransformer, two winding)

Transformer winding data. For a two winding transformer, only winding H and X data is required.

a. For each winding, H, X, y: 1) Nominal voltage, kV 2) Configuration (Δ or Y) and Y winding connection (ungrounded, solid ground or impedance ground)

b. Transformer MVA ratings: 1) Winding H to X, MVA 2) Winding H to Y, MVA 3) Winding X to Y, MVA

c. Transformer impedances, positive and zero sequence: 1) Winding H to X, % X and R at MVA

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2) Winding H to Y, % X and R at MVA 3) Winding X to Y, % X and R at MVA

d. Transformer tap changer information 1) No load or load 2) Tap changer winding location, H, X, Y 3) Available taps

e. Transformer cooling requirements if required from BCTC 1) Load, amps 2) Voltage, single or three phase, kV

4. Transmission Line Data

If a new transmission line is to be included as part of the proposed connection, the following transmission line data shall be provided:

Nominal operating voltage, kV

Line length, KM

Line capacity, amps at ºC

Overhead/underground construction

Positive and zero sequence transmission line characteristics in primary values

a) Series resistance, R Ω b) Series reactance, X Ω c) Shunt susceptance, B μ S (or μ Ω –1)

D1.3 EMTP Data

The following data is required:

Vterm (rated terminal voltage upon which the pu system is based)

Srated (rated MVA of the machine upon which the pu system is based)

Ra (armature resistance) in pu

Xl (armature leakage reactance) in pu

Xd (unsaturated direct-axis synchronous reactance) in pu

Xq (unsaturated quadrature-axis synchronous reactance) in pu

X’d (unsaturated direct-axis transient reactance) in pu

X’q (unsaturated quadrature-axis transient reactance) in pu

X”d (unsaturated direct-axis sub-transient reactance) in pu

X”q (unsaturated quadrature-axis sub-transient reactance) in pu

T’d0 (direct-axis open circuit transient time constant) in seconds

T’q0 (quadrature-axis open circuit transient time constant) in seconds

T”d0 (direct-axis open circuit sub-transient time constant) in seconds

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T”q0 (quadrature-axis open circuit sub-transient time constant) in seconds

Rneutral (the neutral part of the neutral grounding impedance) in pu

Xneutral (the imaginary part of the neutral grounding impedance) in pu

Xc (Canay reactance) in pu

H constants in MW-s/MVA or else J moment of inertia (WR**2) in kg*m**2

For thermal turbine-generator units rated larger than 100 MVA, in addition to the above the following mechanical data shall be provided so that a multi-mass (spring-mass-dashpot) mechanical model can be constructed:

Number of lumped rotating masses on the turbine generator shaft

Moment of inertia (lb.-mass ft2) of each lumped mass

The fraction of the total external mechanical torque of which is applied to the particular mass under consideration

The spring constant [(million pound-ft)/radians] of the shaft section between the present mass and the next one on the shaft

The speed deviation self damping coefficient for the mass under consideration

The mutual damping coefficient pertaining to the present mass with the next mass on the shaft

D2. Generating Unit Testing and Model Validation

D2.1 Generating Facility Data

The PG shall provide to BCTC the information for the PGF as specified in the WECC “Generating Facility Data Requirements8”.

The PG shall review, verify and update the PGF data when any of the following conditions occur:

No later than 180 days after the new PGF is released for Commercial Operation.

No later than 180 days after an existing generating unit re-starts Commercial Operation with modified equipment, control settings, or software that influences the behaviour of the plant with respect to the grid (e.g. excitation retrofit, additional control function within a controller, turbine modification, voltage regulator and power system stabilizer tuning modification, etc.)

At least once every five years.

8 The Generating Facility Data Requirements document” and Generating Unit Baseline Test Requirements document can be found at www.wecc.biz.

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APPENDIX D – DATA REQUIREMENTS

D2.2 Baseline Testing

The GP shall test the generating unit and validate its model data.

The GP shall provide test and validation reports to BCTC. For guidance on the test requirements, refer to the current WECC “Generating Unit Baseline Test Requirements1”.

The testing and associated validation by simulation shall be performed on a generating unit when any of the following conditions have occurred:

If the generating project has not been certified by WECC under Generator Testing Program since January 1997.

No later than 180 days after the new PGF is released for Commercial Operation. In the meantime, the PG shall provide the best available model data supplied by the equipment manufacturer using the WECC approved models including commissioning reports.

No later than 180 days after an existing generating unit re-starts Commercial Operation with modified equipment, control settings, or software that influences its behaviour with respect to the grid (e.g. excitation retrofit, additional control function within a controller, turbine modification, voltage regulator and power system stabilizer tuning modification, etc.), only those portions of the generating unit model that can be influenced by the modifications need to be tested and validated.

No later than 180 days after the PG is notified by WECC that there is evidence that the modeled response of a PGF does not correlate with the actual response, except in instances where the lack of correlation was caused by equipment problems that were subsequently corrected.

D2.3 Model Data Validation

The PG shall perform model data validation and provide a report to BCTC at least once every five years. Schedule of model validation shall be coordinated between the PG and BCTC.

The WECC “Generating Facility Model Data Validation Requirements9” document describes acceptable methods of model data validation by performance comparison.

The PG shall verify that generator control limiters, protection and equipment capabilities are consistent with those reported in the model(s).

9 The WECC Generating Facility Model Data Validation Requirements can be found at www.wecc.biz

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APPENDIX D – DATA REQUIREMENTS

D2.4 Generator Outage Data

The PG is expected to submit generator outage data within 15 days of the end of each month to the Canadian Electricity Association (CEA) and to the North American Electric Reliability Council (NERC) in the United States.

The reporting procedure as described in BC Hydro System Operating Order 1P-14 (Generation Equipment – Status Reporting) is based on a method developed by the CEA of assigning "states" to the operation of a unit. Prior to full commercial in-service, BCTC will supply the PG with a copy of such order.

Alternatively, the PG can make separate arrangement with BC Hydro for a joint submission.

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APPENDIX E – DECLARATION OF COMPATIBILITY

Appendix E – Declaration of Compatibility

The PG shall comply with the various levels of Declarations of Compatibility as listed below and available at the BCTC website. Please see System Operating Order 1T-35 at www.bctc.com/NR/rdonlyres/610E3D35-3383-4A3A-8DAB-0AFF27846AF6/0/1T35.pdf. These declarations refer to key aspects where BCTC must be confident of the correct operation, setting, calibration and/or installation of equipment.

Each declaration must be signed by BCTC and the PG agreeing that the PG’s interconnection is compatible with the Transmission System and is capable of receiving electricity, generating electricity for commissioning purposes, or full commercial generating electricity.

This may include, but is not limited to, generator performance, protective relaying, telecommunications, revenue metering, and shall confirm the compatibility of the PG’s equipment and controls.

Requirements for “Declaration of Compatibility - Load”

The compatibility of load describes conditions that must be satisfied before the PGF can be connected to receive electricity from the Transmission System and usually occurs during construction.

Requirements for “Declaration of Compatibility – Generator (1st Synchronization)”

The compatibility of generation (1st Synchronization) describes conditions that must be satisfied before the PGF can be connected to generate electricity for the purposes of testing and commissioning the facility or its components.

Requirements for “Declaration of Compatibility – Generator (Operating)”

The compatibility of generation (operating) describes conditions that must be satisfied before the PGF can be connected to commercially generate electricity.

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Appendix F – Permissible Voltage Dips – Borderline of Visibility Curve

Appendix F – Permissible Voltage Dips – Borderline of Visibility Curve

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